10-Q

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2018

 or

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

For the transition period from to

Commission File No. 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware	73-1268729
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

801 Travis Street, Suite 2100, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

713-568-4725

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) 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 website, 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 an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐ (Do not check if a smaller reporting company)	Smaller reporting company	☑

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

Number of shares of common stock, par value $0.01 per share outstanding as of November 14, 2018:  10,925,513

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

TABLE OF CONTENTS

GLOSSARY OF SELECTED ENERGY AND FINANCIAL TERMS		4
PART I. FINANCIAL INFORMATION		6
ITEM 1.  FINANCIAL STATEMENTS		6
	Consolidated Balance Sheets (Unaudited)	6
	Consolidated Statements of Operations (Unaudited)	7
	Consolidated Statements of Cash Flows (Unaudited)	8
	Notes to Consolidated Financial Statements	9
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		36
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		53
ITEM 4. CONTROLS AND PROCEDURES		53
PART II. OTHER INFORMATION		54
ITEM 1.  LEGAL PROCEEDINGS		54
ITEM 1A.  RISK FACTORS		54
ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		54
ITEM 3.  DEFAULTS UPON SENIOR SECURITIES		55
ITEM 4.  MINE SAFETY DISCLOSURES		55
ITEM 5.  OTHER INFORMATION		55
ITEM 6.  EXHIBITS		55
SIGNATURES		56

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

INTRODUCTION

This Quarterly Report for the quarterly period ended September 30, 2018 (this “Quarterly Report”) is a document that U.S. public companies file with the Securities and Exchange Commission (“SEC”) each quarter. Part I, Item 1. of the Quarterly Report contains financial information, including consolidated financial statements and related notes. Part I, Item 2. of this Quarterly Report provides management’s discussion and analysis of our financial condition and results of operations. We hope investors will find it useful to have this information in a single document.

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

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

In this Quarterly Report, and from time to time throughout the year, we share our expectations for our future performance. These forward-looking statements include statements about our business plans; our expected financial performance, including the anticipated effect of strategic actions; previously reported material weakness in our internal control over financial reporting; economic, political and market conditions; and other factors that could affect our future results of operations or financial condition, including, without limitation, statements under the section entitled “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1. Legal Proceedings,” and “Part II, Item 1A. Risk Factors.” Any statements we make that are not matters of current reportage or historical fact should be considered forward-looking. Such statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “will,” and similar expressions. By their nature, these types of statements are uncertain and are not guarantees of our future performance. Our forward-looking statements represent our estimates and expectations at the time of disclosure. However, circumstances change constantly, often unpredictably, and investors should not place undue reliance on these statements. Many events beyond our control will determine whether our expectations will be realized. We disclaim any current intention or obligation to revise or update any forward-looking statements, or the factors that may affect their realization, whether considering new information, future events or otherwise, and investors should not rely on us to do so.

In accordance with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (the “Annual Report”), “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the period ended March 31, 2018, “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the period ended June 30, 2018, and “Part II, Item 1A. Risk Factors” in this Quarterly Report explain some of the important factors that may cause actual results to be materially different from those that we anticipate.

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

GLOSSARY OF SELECTED ENERGY AND FINANCIAL TERMS

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

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

Energy Terms

Atmospheric gas oil (“AGO”). 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.

Barrel (“bbl”). A unit of volume equal to 42 U.S. gallons.

Barrels per Day (“bpd”). A measure of the bbls of daily output produced in a refinery or transported through a pipeline.

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.

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 heavy oil-based mud blendstock (“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.

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.

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.

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 about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.

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.

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.

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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

Product Slate. Represents type and quality of products produced.

Propane. A byproduct of natural gas processing and petroleum refining. Propane is one of a group of liquefied petroleum gases. Others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof.

Refined petroleum products. Refined petroleum products are derived from crude oil and condensate that have been processed through various refining methods. The resulting products include gasoline, home heating oil, jet fuel, diesel, lubricants and the raw materials for fertilizer, chemicals, and pharmaceuticals.

Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil and condensate is separated and transformed into petroleum products.

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 byproduct 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, 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.

Throughput. The volume processed through a unit or a refinery or transported through a pipeline.

Turnaround. Scheduled large-scale maintenance activity wherein an entire process unit is taken offline for a week or more for comprehensive revamp and renewal.

Yield. The percentage of refined petroleum products that is produced from crude oil and other feedstocks.

Financial and Performance Measures 

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).

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.

EBITDA. Reflects earnings before: (i) interest income (expense), (ii) income taxes, and (iii) depreciation and amortization.

Final Arbitration Award. Damages and attorney fees and related expenses awarded to GEL Tex Marketing, LLC (“GEL”) by an arbitrator on August 11, 2017, in arbitration proceedings between LE and GEL related to a contractual dispute.

Gross Profit.Calculated as total revenue less cost of sales; reflected as a dollar ($) amount.

Gross Margin. Calculated as gross profit divided by total revenue; reflected as a percentage (%).

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.

Other Operating Expenses. Represents costs associated with our pipeline assets and leasehold interests in oil and gas properties.

Refining Gross Profit per Bbl. Calculated as refined petroleum product sales less cost of sales divided by the volume, in bbls, of refined petroleum products sold during the period; reflected as a dollar ($) amount per bbl.

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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	September 30,	December 31,
	2018	2017
	(in thousands, except share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$24	$495
Restricted cash	49	49
Accounts receivable, net	1,669	1,357
Accounts receivable, related party	-	653
Prepaid expenses and other current assets	447	1,207
Deposits	194	129
Inventory	2,627	3,089
Refundable federal income tax, current	108	-
Total current assets	5,118	6,979
LONG-TERM ASSETS
Total property and equipment, net	65,109	64,597
Restricted cash, noncurrent	1,602	1,602
Surety bonds	230	230
Deferred tax assets, net	108	-
Total long-term assets	67,049	66,429
TOTAL ASSETS	$72,167	$73,408
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default	$34,988	35,544
Long-term debt, related party, current portion, in default	6,532	4,000
Interest payable, in default	2,734	2,135
Interest payable, related party, in default	1,374	892
Accounts payable	2,617	2,344
Accounts payable, related party	1,378	974
Asset retirement obligations, current portion	2,519	2,315
Accrued expenses and other current liabilities	863	1,160
Accrued arbitration award payable	23,128	27,128
Total current liabilities	76,133	76,492
LONG-TERM LIABILITIES
Deferred revenues and expenses	10	42
Capital lease obligation, net of current portion	10	-
Long-term debt, related party, net of current portion	-	1,608
Total long-term liabilities	20	1,650
TOTAL LIABILITIES	76,153	78,142
Commitments and contingencies (Note 18)
STOCKHOLDERS' DEFICIT
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,925,513
shares issued at September 30, 2018 and December 31, 2017, respectively)	109	109
Additional paid-in capital	36,907	36,907
Retained earnings (deficit)	(41,002)	(41,750)
TOTAL STOCKHOLDERS' DEFICIT	(3,986)	(4,734)
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$72,167	$73,408

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(in thousands, except share and per-share amounts)
REVENUE FROM OPERATIONS
Refinery operations	$94,468	$66,133	$254,245	$174,668
Tolling and terminaling	1,075	766	2,659	2,174
Total revenue from operations	95,543	66,899	256,904	176,842
COST OF OPERATIONS
Cost of sales	93,195	58,786	245,786	165,185
Refinery operating expenses	1,085	1,758	4,384	6,223
Other operating expenses	33	68	133	183
Arbitration award and associated fees	-	-	-	24,339
General and administrative expenses	929	1,240	2,277	2,854
Depletion, depreciation and amortization	478	455	1,396	1,356
Accretion of asset retirement obligations	61	72	205	216
Total cost of operations	95,781	62,379	254,181	200,356
Income (loss) from operations	(238)	4,520	2,723	(23,514)
OTHER INCOME (EXPENSE)
Easement, interest and other income	18	27	20	410
Interest and other expense	(760)	(601)	(2,255)	(2,028)
Gain on disposal of property	-	-	-	1,834
Total other income (expense)	(742)	(574)	(2,235)	216
Income (loss) before income taxes	(980)	3,946	488	(23,298)
			-
Income tax benefit	43	-	260	-
Net income (loss)	$(937)	$3,946	$748	$(23,298)
Income (loss) per common share:
Basic	$(0.09)	$0.36	$0.07	$(2.19)
Diluted	$(0.09)	$0.36	$0.07	$(2.19)
Weighted average number of common shares outstanding:
Basic	10,925,513	10,818,371	10,925,513	10,644,654
Diluted	10,925,513	10,818,371	10,925,513	10,644,654
Dividends declared per common share outstanding	$0.00	$0.00	$0.00	$0.00

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2018	2017
	(in thousands)
OPERATING ACTIVITIES
Net income (loss)	$748	$(23,298)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization	1,396	1,356
Deferred income tax	(216)	-
Amortization of debt issue costs	96	96
Accretion of asset retirement obligations	205	216
Common stock issued for services	-	30
Changes in operating assets and liabilities
Accounts receivable	(312)	1,395
Accounts receivable, related party	653	101
Prepaid expenses and other current assets	760	(585)
Deposits and other assets	(65)	(25)
Inventory	462	(700)
Accrued arbitration award	(4,000)	27,628
Accounts payable, accrued expenses and other liabilities	1,023	(12,804)
Accounts payable, related party	404	454
Net cash provided by (used in) operating activities	1,154	(6,136)
INVESTING ACTIVITIES
Capital expenditures	(1,826)	(1,777)
Net cash used in investing activities	(1,826)	(1,777)
FINANCING ACTIVITIES
Proceeds from issuance of debt	-	3,678
Payments on debt	(723)	(1,120)
Net activity on related-party debt	924	968
Net cash provided by financing activities	201	3,526
Net change in cash, cash equivalents, and restricted cash	(471)	(4,387)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	2,146	6,083
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$1,675	$1,696
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable and capital leases	$82	$1,651
Financing of guaranty fees via long-term debt, related party	$485	$171
Conversion of accounts payable to short-term notes	$-	$-
Conversion of related-party notes to common stock	$-	$831
Interest paid	$2,173	$1,574
Income taxes paid	$-	$-

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

Notes to Consolidated Financial Statements
(1)	Organization

Nature of Operations. Blue Dolphin Energy Company is a publicly-traded Delaware corporation primarily engaged in the refining and marketing of petroleum products. We also provide tolling and storage terminaling services. Our assets, which are located in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and approximately 1.1 million bbls of petroleum storage tanks (collectively the “Nixon Facility”). Pipeline transportation and oil and gas operations are no longer active.

Structure and Management.Blue Dolphin is controlled by Lazarus Energy Holdings, LLC (“LEH”). LEH operates and manages all Blue Dolphin properties pursuant to an Amended and Restated Operating Agreement (the “Amended and Restated Operating Agreement”). Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. Together LEH and Jonathan Carroll own 80.2% of our common stock, par value $0.01 per share (the “Common Stock”). (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Amended and Restated Operating Agreement, and Jonathan Carroll.)

We have the following active subsidiaries:

●

Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”);

●

Blue Dolphin Petroleum Company, a Delaware corporation;

●

Blue Dolphin Services Co., a Texas corporation (“BDSC”);

●

Lazarus Energy, LLC, a Delaware limited liability company (“LE”);

●

Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”); and

●

Nixon Product Storage, LLC, a Delaware limited liability company (“NPS”).

In June 2018, Blue Dolphin acquired 100% of the issued and outstanding membership interests of NPS from Lazarus Midstream Partners, L.P., an affiliate of LEH, pursuant to an Assignment Agreement. The assignment was accounted for as a combination of entities under common control. See “Note (5) NPS Assignment” of this Quarterly Report for further information related to the NPS assignment.

See "Part I, Item 1. Business” and “Item 2. Properties” in the Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets.

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BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

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:

●

Final Arbitration Award and Settlement Agreement – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of approximately $31.3 million. As of the date of this report, LE has paid $9.2 million to GEL towards reducing the outstanding balance of the Final Arbitration Award. After the $3.7 million initial payment to GEL in September 2017, LE has made payments to GEL at $0.5 million per month.

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

On July 20, 2018, LE, NPS, and Blue Dolphin, together with LEH, Carroll & Company Financial Holdings, L.P. (“C&C”), and Jonathan Carroll (collectively referred to herein as the “Lazarus Parties”), entered into a Settlement Agreement with GEL (the “Settlement Agreement”), 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 the GEL Arbitration (the “Settlement”), subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon payment by the Lazarus Parties to GEL of $10.0 million in cash (the “Settlement Payment”) and $0.5 million in cash at the end of each calendar month until the Settlement Payment is paid (the “Interim Payments”) or the Settlement Agreement is terminated. The Interim Payments will not be applied to reduce the amount of the Settlement Payment, but such payments will reduce the Final Arbitration Award. At September 30, 2018 and December 31, 2017, accrued arbitration award payable on our consolidated balance sheet was $23.1 million and $27.1 million, respectively. At the time of the Settlement, the difference between the Settlement Payment and the amount we have accrued on our consolidated balance sheet for arbitration award payable will be recognized as a gain on our consolidated statement of operations.

The Settlement Agreement restricts the Lazarus Parties from taking certain actions without the prior written consent of GEL, including: (i) the incurrence of any debt not specifically excepted in the Settlement Agreement, (ii) the establishment of any liens not specifically excepted in the Settlement Agreement, (iii) the disposition of any assets other than certain ordinary course sales to unaffiliated third parties, payments to unaffiliated third-party trade creditors and scheduled debt payments, (iv) the entrance into any transactions with affiliates not specifically excepted in the Settlement Agreement, (v) the failure to pay debts generally as they become due, and (vi) the entrance into a bankruptcy, reorganization or similar proceeding. A violation of any of the restrictions in the Settlement Agreement, as well as the failure of the Lazarus Parties to make Interim Payments as they become due, will constitute an event of default under the Settlement Agreement which, subject to certain cure periods, would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award.

The Lazarus Parties are exploring the possibility of obtaining a commercial loan or other financing in an aggregate principal amount equal to the Settlement Payment (the “Settlement Financing”), subject to obtaining the consent of Veritex Community Bank (“Veritex”), as lender under certain loan agreements with the Lazarus Parties and their affiliates. Under the Settlement Agreement, the Lazarus Parties are required to work in good faith and take reasonable actions necessary to obtain the Settlement Financing in accordance with the terms of the Settlement Agreement. Prior to the consummation of the Settlement Financing, the Lazarus Parties are required to: (i) cause NPS to consummate the Settlement Financing and restrict its ability to commence a bankruptcy case, (ii) assign to NPS certain tank leases that will constitute collateral for the Settlement Financing, and (iii) cause NPS to assume joint and several liability for all or a portion of the Final Arbitration Award. The failure to achieve certain milestones in connection with obtaining the Settlement Financing will constitute an event of default under the Settlement Agreement, which would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award.

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BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Simultaneously with the execution of the Settlement Agreement, Jonathan Carroll and C&C entered into a Security Agreement pursuant to which Jonathan Carroll and C&C agreed to secure up to $10.0 million of LE’s obligations under the Final Arbitration Award with a security interest in their equity in LEH.

The Settlement Agreement will terminate, unless extended in writing by GEL, on December 31, 2018 if the Settlement Payment is not made on or before such date, and the Settlement Agreement may be terminated by GEL following the occurrence of an event of default under the Settlement Agreement, as described above. Pursuant to the Settlement Agreement, the parties agreed to terminate the Letter Agreement, and GEL agreed not to take any action to execute or collect on the Final Arbitration Award and to take all action necessary to continue the District Court Action until the earlier of: (i) the date on which the Settlement Payment is paid or (ii) the termination of the Settlement Agreement.

Blue Dolphin can provide no assurance that the conditions necessary for consummation of the Settlement will be met. If certain conditions are not met or the Settlement Agreement is terminated, GEL may seek to enforce the Final Arbitration Award against the Lazarus Parties, in which case: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

●

Veritex Secured Loan Agreement Event of Default – Veritex, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the Settlement Agreement. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Additionally, Veritex must ultimately approve the Settlement. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future.

We can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement Agreement, any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

Operating Risks. Successful execution of our business plan depends on several key factors, including the Settlement with GEL, having adequate crude oil and condensate supplies, maintaining safe and reliable operations at the Nixon Facility, having favorable margins on refined petroleum products, and meeting contractual obligations. (See “Part I, Item 1. Business – Business Strategies” in the Annual Report for information related to our business plan.)

For the three months ended September 30, 2018, we reported a net loss of $0.9 million, or a loss of $0.09 per share, compared to net income of $3.9 million, or income of $0.36 per share, for the three months ended September 30, 2017. Net loss for the three months ended September 30, 2018 was primarily the result of lower and sometimes negative margins on refined petroleum products, while net income for the three months ended September 30, 2017 was primarily the result of favorable margins for refined petroleum products.  

11

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

For the nine months ended September 30, 2018, we reported net income of $0.7 million, or income of $0.07 per share, compared to a net loss of $23.3 million, or a loss of $2.19 per share, for the nine months ended September 30, 2017. The nine months ended September 30, 2017 included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million in arbitration award and associated fees and represented an expense of $2.29 per share. Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.26 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis declined $0.03 between the periods, which was primarily the result of slightly lower margins for refined petroleum products.

Execution of our business plan was hindered during the three months ended September 30, 2018 by several factors, including:

●

Working Capital Deficits – We had a working capital deficit of $71.0 million at September 30, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $29.5 million at September 30, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017.

●

Crude Supply – Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, and other factors, as noted above.

●

Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018 LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would 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 sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to the Settlement Agreement with GEL, or provide future waivers of any financial covenant defaults, which would have an adverse impact on our financial position and results of operations.

We are continuing aggressive actions to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability. However, there can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. If Veritex does not approve the Settlement or if the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

For additional disclosures related to the Final Arbitration Award, the GEL Letter Agreement, the Settlement Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Quarterly Report:

●

Part I, Item 1. Financial Statements, Notes to Consolidated Financial Statements:

Note (9) Related Party Transactions

Note (11) Long-Term Debt, Net

Note (18) Commitments and Contingencies – Legal Matters

12

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

●

Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations:

Final Arbitration Award

Results of Operations

Liquidity and Capital Resources

●

Part II, Item 1. Legal Proceedings

●

Part II, Item 1A. Risk Factors

(2) Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Articles 8 and 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. 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.

The consolidated balance sheet as of December 31, 2017 was derived from the audited financial statements at that date.  The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report.  Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2018, or for any other period.

(3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.

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 GAAP. We believe our current estimates are reasonable and appropriate; however, actual results could differ from those estimated.

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: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks.

Inventory.Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of sales. (See “Note (7) Inventory” for additional disclosures related to our inventory.)

13

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance on accounting for the impairment or disposal of long-lived assets, management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, our pipeline assets were fully impaired. All pipeline transportation services to third parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines.

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

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

(See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name. We account for intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we determined trade name to have an indefinite useful life, and we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2017. Upon completion of that testing, our trade name asset was fully impaired at December 31, 2017.

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability. (See “Note (11) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

14

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Revenue Recognition.

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

Refinery Operations Revenue. Revenue from the sale of refined petroleum products is recognized when the product is sold to a customer in fulfillment of performance obligations. Each barrel of refined petroleum product, or other unit of measure, 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 in accordance with the terms of the respective sales agreement. We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant. Transportation, shipping, and handling costs incurred are included in cost of sales. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

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

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines 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 the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our 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 September 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”).

15

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

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 September 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.)

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the 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. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented.

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

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and 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. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (12) Asset Retirement Obligations” for additional information related to our AROs.)

Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which 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. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. 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.

16

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.)

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include:

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

New Pronouncements Issued, Not Yet Effective. The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows:

ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In July 2018, FASB issued ASUs 2018-11 and 2018-10. ASU 2018-11 provides entities with relief from the costs of implementing certain aspects of ASU 2016-02 (codified as ASC 842). Specifically, under the amendments in ASU 2018-11: (i) Entities may elect not to recast the comparative periods presented when transitioning to ASC 842 (Issue 1), and (ii) Lessors may elect not to separate lease and non-lease components when certain conditions are met (Issue 2). ASU 2018-10 made 16 separate amendments to ASC 842. For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in: (i) the recognition of a liability to make lease payments and a right-to-use asset representing our right to use the underlying asset on our consolidated balance sheets and (ii) the recognition of an expense on our consolidated statements of operations each month as we amortize the right-to-use asset.

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

17

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

ASU 2018-07, Compensation – Stock Compensation (Topic 718). In June 2018, FASB issued ASU 2018-07. This guidance expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The amendments in ASU 2018-07 are effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year.Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

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

(4) Business 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 related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility.

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

	Three Months Ended September 30,
	2018				2017
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Corporate
	Operations	Terminaling	& Other	Total	Operations	& Other	Total
Net revenues (excluding intercompany fees and sales)	$94,468	$1,075	$-	$95,543	$66,899	$-	$66,899
Intercompany fees and sales	(873)	873	-	-	-	-	-
Operation costs and expenses(1)
Cost of materials and other	(92,571)	-	-	(92,571)	(58,786)	-	(58,786)
Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below)	(1,085)	(624)	(94)	(1,803)	(1,758)	(140)	(1,898)
Segment contribution margin	$(61)	$1,324	$(94)	$1,169	$6,355	$(140)	$6,215
General and administrative expenses	(375)	(65)	(489)	(929)	(913)	(327)	(1,240)
Depreciation and amortization	(432)	(46)	-	(478)	(452)	(3)	(455)
Interest and other non-operating expenses, net				(742)			(574)
Income (loss) before income taxes				(980)			3,946
Income tax benefit				43			-
Net income (loss)				$(937)			$3,946
Capital expenditures	$372	$223	$-	$595	$539	$-	$539
Identifiable assets	$51,816	$19,425	$926	$72,167	$70,792	$2,068	$72,860

(1)  Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

18

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

	Nine Months Ended September 30,
	2018				2017
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Corporate
	Operations	Terminaling	& Other	Total	Operations	& Other	Total
Net revenues (excluding intercompany fees and sales)	$254,245	$2,659	$-	$256,904	$176,842	$-	$176,842
Intercompany fees and sales	(2,419)	2,419	-	-	-	-	-
Operation costs and expenses(1)
Cost of materials and other	(244,380)	-	-	(244,380)	(189,525)	-	(189,525)
Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below)	(3,698)	(2,092)	(338)	(6,128)	(6,223)	(399)	(6,622)
Segment contribution margin	$3,748	$2,986	$(338)	$6,396	$(18,906)	$(399)	$(19,305)
General and administrative expenses	(929)	(156)	(1,192)	(2,277)	(1,960)	(894)	(2,854)
Depreciation and amortization	(1,258)	(138)	-	(1,396)	(1,348)	(8)	(1,356)
Interest and other non-operating income (expenses), net(2)				(2,235)			217
Income (loss) before income taxes				488			(23,298)
Income tax benefit				260			-
Net income (loss)				$748			$(23,298)
Capital expenditures	$1,141	$767	$-	$1,908	$3,428	$-	$3,428
Identifiable assets	$51,816	$19,425	$926	$72,167	$70,792	$2,068	$72,860

(1)

Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

(2)

Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

(5) NPS Assignment

In June 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS, a Delaware limited liability company, from Lazarus Midstream Partners, L.P. (“Lazarus Midstream”), an affiliate of LEH, pursuant to an Assignment Agreement. The transaction represents transfer of a vacant shell entity owned by Lazarus Midstream to Blue Dolphin for the nominal fee of $10.00. The assignment of interest facilitates the Lazarus Parties exploring the possibility of obtaining the Settlement Financing under the 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 the three and nine months ended September 30, 2018. NPS did not have significant assets, liabilities or results of operations for the three and nine months ended September 30, 2017. 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.

19

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

(6) Prepaid Expenses and Other Current Assets

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

	September 30,	December 31,
	2018	2017
	(in thousands)
Prepaid insurance	$408	$294
Other prepaids	39	-
Prepaid crude oil and condensate	-	913
	$447	$1,207

(7) Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,	December 31,
	2018	2017
	(in thousands)
Crude oil and condensate	$1,571	$961
AGO	449	213
HOBM	256	1,558
Naphtha	234	170
Chemicals	94	162
Propane	18	17
LPG mix	5	8
	$2,627	$3,089

(8) Property, Plant and Equipment, Net

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

	September 30,	December 31,
	2018	2017
	(in thousands)
Refinery and facilities	$54,210	$51,432
Land	566	566
Other property and equipment	747	653
	55,523	52,651
Less: Accumulated depletion, depreciation, and amortization	(9,892)	(8,495)
	45,631	44,156
Construction in progress	19,478	20,441
	$65,109	$64,597

20

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

We capitalize interest cost incurred on funds used to construct property, plant, and equipment. Capitalized interest, which is recorded as part of the asset to which it relates, is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $4.2 million and $3.9 million at September 30, 2018 and December 31, 2017, respectively. We expect construction of petroleum storage tanks at the Nixon Facility to continue until year end.

(9) Related Party Transactions

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

Related Parties.

LEH. LEH is our controlling shareholder. Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. Together, LEH and Jonathan Carroll own 80.2% of our Common Stock. Related party agreements with LEH include: (i) an Amended and Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL, (iv) an Amended and Restated Promissory Note with Blue Dolphin, and (v) a Debt Assumption Agreement with LE. Additionally, in June 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS from Lazarus Midstream pursuant to an Assignment Agreement. (See “Note (5) NPS Assignment” for further discussion related to the NPS transaction.)

Ingleside Crude, LLC (“Ingleside”). Ingleside is a related party of LEH and Jonathan Carroll. Blue Dolphin is party to an Amended and Restated Promissory Note with Ingleside.

Lazarus Marine Terminal I, LLC (“LMT”). LMT is a related party of LEH and Jonathan Carroll. LE is party to a Dock Tolling Agreement with LMT.

Jonathan Carroll. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin. Related party agreements with Jonathan Carroll include: (i) Amended and Restated Guaranty Fee Agreements with LE and LRM and (ii) an Amended and Restated Promissory Note with Blue Dolphin.

Currently, we depend on LEH and its affiliates (including Jonathan Carroll and Ingleside) for financing when revenue from operations and borrowings under bank facilities are insufficient to meet our liquidity needs. Such borrowings are reflected in our consolidated balance sheets in accounts payable, related party, and/or long-term debt, related party.

Operations Related Agreements.

Amended and Restated Operating Agreement. LEH operates and manages all Blue Dolphin properties pursuant to the Amended and Restated Operating Agreement. The Amended and Restated Operating Agreement, which was restructured in 2017 following cessation of crude supply and marketing activities under the Crude Supply Agreement and Joint Marketing Agreement with GEL, expires: (i) April 1, 2020, (ii) upon written notice by either party to the Amended and Restated Operating Agreement of a material breach by the other party, or (iii) upon 90 days’ notice by the Board if the Board determines that the Amended and Restated Operating Agreement is not in our best interest. LEH receives an operating fee of 5% of Blue Dolphin’s direct operating expenses. LEH’s operating fee and Blue Dolphin’s direct operating expenses are reflected within refinery operating expenses in our consolidated statements of operations.

Jet Fuel Sales Agreement. LE sells jet fuel to LEH pursuant to a Jet Fuel Sales Agreement. LEH resells the jet fuel purchased from LE to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. The Jet Fuel Sales Agreement terminates on the earliest to occur of: (a) a one-year term expiring March 31, 2019 plus a 30-day carryover or (b) delivery of a maximum quantity of jet fuel as defined therein. Sales to LEH under the Jet Fuel Sales Agreement are reflected within refinery operations revenue in our consolidated statements of operations. (LRM previously leased petroleum storage tanks to LEH for the storage of the jet fuel under a Terminal Services Agreement. The Terminal Services Agreement was terminated as described below).

Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leased petroleum storage tanks from LRM for the storage of LEH purchased jet fuel under the Jet Fuel Sales Agreement (as described above). The Terminal Services Agreement was terminated in June 2017. Rental fees received from LEH under the Terminal Services Agreement are reflected within tolling and terminaling revenue in our consolidated statements of operations.

21

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Amended and Restated Tank Lease Agreement. Pursuant to an Amended and Restated Tank Lease Agreement with Ingleside, LE leased petroleum storage tanks to meet periodic, additional storage needs. The Amended and Restated Tank Lease Agreement was terminated in July 2017. Rental fees owed to Ingleside under the tank lease agreement are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets. Amounts expensed as rental fees to Ingleside under the Amended and Restated Tank Lease Agreement are reflected within refinery operating expenses in our consolidated statements of operations.

Dock Tolling Agreement. In May 2016, LE entered a Dock Tolling Agreement with LMT to facilitate loading and unloading of petroleum products by barge at LMT’s dock facility in Ingleside, Texas. The Dock Tolling Agreement has a five-year term and may be terminated at any time by the agreement of both parties. LE pays LMT a flat reservation fee monthly. The reservation fee includes tolling volumes up to 84,000 gallons per day. Excess tolling volumes are subject to an increased per gallon rate. Amounts expensed as tolling fees under the Dock Tolling Agreement are reflected in the cost of sales in our consolidated statements of operations.

Financial Agreements.

BDPL Loan Agreement (In Default). In August 2016, BDPL entered a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “BDPL Loan Agreement”). The BDPL Loan Agreement matured on August 15, 2018. Interest is still accruing at a rate of 16.00%. The BDPL Loan Agreement is currently in default due to non-payment.

The proceeds of the BDPL Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the BDPL Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the BDPL Loan Agreement is reflected in interest payable, related party, current portion in our consolidated balance sheets.

Promissory Notes. We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. During 2017, LEH and its affiliates (Ingleside and Jonathan Carroll) provided working capital to Blue Dolphin in the form of non-cash advances, such as conversions of accounts payable to debt. These non-cash advances are reflected in the below promissory notes. There can be no assurance that LEH and its affiliates will continue to fund our working capital requirements. Outstanding principal and accrued interest owed under these promissory notes are reflected in long-term debt, related party, current portion in our consolidated balance sheets.

●

June LEH Note – In March 2017, Blue Dolphin entered a promissory note with LEH (the “March LEH Note”). In June 2017, the March LEH Note was amended and restated to increase the principal amount (the “June LEH Note”). The June LEH Note accrues interest at a rate of 8.00% and has a maturity date of January 2019. Interest under the June LEH Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

●

March Ingleside Note – In March 2017, a promissory note between Blue Dolphin and Ingleside was amended and restated (the “March Ingleside Note”) to increase the principal and extend the maturity date to January 2019. Interest under the March Ingleside Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

●

March Carroll Note – In March 2017, a promissory note between Blue Dolphin and Jonathan Carroll was amended and restated (the “March Carroll Note”) to increase the principal amount, revise the payment terms to reflect payment in cash and shares of Blue Dolphin Common Stock, and extend the maturity date to January 2019. Interest under the March Carroll Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

22

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3.6 million to GEL relating to the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3.7 million of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John Kissick. Debt held by John Kissick, including the debt associated with the Debt Assumption Agreement, is reported in this Quarterly Report as the Notre Dame Debt (defined below) and is reflected in long-term debt less unamortized debt issue costs, current portion in our consolidated balance sheets, as it is currently in default. (See “Note (11) Long-Term Debt, Net” for further discussion related to the Notre Dame Debt.)

Amended and Restated Guaranty Fee Agreements. Pursuant to Amended and Restated Guaranty Fee Agreements, Jonathan Carroll earns fees for providing his personal guarantee on certain LE and LRM long-term debt. Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain LE and LRM loan agreements. Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets. Amounts expensed related to Amended and Restated Guarantee Fee Agreements are reflected within interest and other expense in our consolidated statements of operations.

Financial Statements Impact.

Consolidated Balance Sheets. Accounts receivable, related party from LEH associated with the Jet Fuel Sales Agreement were $0 and $0.7 million at September 30, 2018 and December 31, 2017, respectively. Accounts payable, related party to LMT associated with the Dock Tolling Agreement were $1.4 million and $1.0 million at September 30, 2018 and December 31, 2017, respectively.

Long-term debt, related party associated with the BDPL Loan Agreement, March Ingleside Note, and the March Carroll Note as of the dates indicated was as follows:

	September 30,	December 31,
	2018	2017
	(in thousands)
LEH	$4,303	$4,000
Ingleside	1,263	1,169
Jonathan Carroll	966	439
	6,532	5,608
Less: Long-term debt, related party,
current portion	(6,532)	(4,000)
	$-	$1,608

Accrued interest associated with the BDPL Loan Agreement was $1.4 million and $0.9 million at September 30, 2018 and December 31, 2017, respectively.

23

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Consolidated Statements of Operations. Revenue from related parties was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except percent amounts)
Refinery operations
LEH	$27,299	28.7%	$20,803	31.1%	$73,415	28.6%	$59,786	33.8%
Other customers	67,169	70.4%	45,330	67.8%	180,830	70.4%	114,882	65.0%
Tolling and terminaling
LEH	-	0.0%	56	0.1%	-	0.0%	675	0.4%
Other customers	1,075	0.9%	710	1.0%	2,659	1.0%	1,499	0.8%
	$95,543	100.0%	$66,899	100.0%	$256,904	100.0%	$176,842	100.0%

Fees associated with the Dock Tolling Agreement with LMT totaled $0.2 million for both the three months ended September 30, 2018 and 2017. Fees associated with the Dock Tolling Agreement with LMT totaled $0.6 million for both the nine months ended September 30, 2018 and 2017.

Expenses and fees associated with the Amended and Restated Operating Agreement with LEH for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	Amount	per bbl	Amount	per bbl	Amount	per bbl	Amount	per bbl
	(in thousands, except per bbl amounts)
Blue Dolphin's direct operating expenses
	$1,033	0.85	$1,674	1.46	$4,175	1.22	$5,927	1.84
LEH operating fee	52	0.04	84	0.07	209	0.06	296	0.09
Total refinery operating expenses	$1,085	$0.89	$1,758	$1.53	$4,384	$1.28	$6,223	$1.93

For the three months ended September 30, 2018, refinery operating expenses decreased approximately $0.7 million, or $0.64 per bbl, compared to the same period a year earlier. For the nine months ended September 30, 2018, refinery operating expenses decreased approximately $1.8 million, or $0.65 per bbl, compared to the same nine-month period a year earlier. The decrease in refinery operating expenses was due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement, as well as management’s efforts to reduce spending.

24

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Interest expense associated with the BDPL Loan Agreement, the Restated Guaranty Fee Agreements, and the related-party promissory notes (the June LEH Note, the March Ingleside Note, and March Carroll Note) for the periods indicated was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(in thousands)
Jonathan Carroll	$180	$171	$519	$521
LEH	166	164	489	542
Ingleside	25	23	96	69
	$371	$358	$1,104	$1,132

(10) Accrued Expenses and Other Current Liabilities

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

	September 30,	December 31,
	2018	2017
	(in thousands)
Board of director fees payable	$270	$207
Other payable	205	116
Unearned revenue	125	450
Property taxes	122	131
Customer deposits	109	109
Excise and income taxes payable	32	79
Insurance	-	68
	$863	$1,160

(11) Long-Term Debt, Net

Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following:

	September 30,	December 31,
	2018	2017
	(in thousands)
First Term Loan Due 2034 (in default)	$22,663	$23,199
Second Term Loan Due 2034 (in default)	9,344	9,502
Notre Dame Debt (in default)	4,978	4,978
Capital leases	51	-
	$37,036	$37,679
Less: Current portion of long-term debt, net	(34,988)	(35,544)
Less: Unamortized debt issue costs	(2,038)	(2,135)
	$10	$-

25

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following:

	September 30,	December 31,
	2018	2017
	(in thousands)
First Term Loan Due 2034 (in default)	$1,674	$1,674
Second Term Loan Due 2034 (in default)	768	768
Less: Accumulated amortization	(404)	(307)
	$2,038	$2,135

Amortization expense was $0.03 million for both the three months ended September 30, 2018 and 2017. Amortization expense was $0.1 million for both the nine months ended September 30, 2018 and 2017.

Accrued interest associated with long-term debt, net is reflected as interest payable, in default and interest payable, related party, in default in our consolidated balance sheets. Accrued interest as of the dates indicated consisted of the following:

	September 30,	December 31,
	2018	2017
	(in thousands)
Notre Dame Debt (in default)	$2,643	$2,046
BDPL Loan Agreement (related party, in default)	1,374	892
Second Term Loan Due 2034 (in default)	52	49
First Term Loan Due 2034 (in default)	39	40
	4,108	3,027
Less: Interest payable, current portion	(4,108)	(3,027)
Long-term interest payable, net of current portion	$-	$-

Related Party. See “Note (9) Related Party Transactions” for additional disclosures with respect to related party long-term debt.

First Term Loan Due 2034 (In Default). LE has a 2015 loan agreement and related security agreementwith Veritex as administrative agent and lender. The loan agreement is for a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”). The First Term Loan Due 2034 matures in June 2034, has a current monthly payment of principal and interest of $0.2 million, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use 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.

26

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

 

As described elsewhere in this Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LE was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LE entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the First Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the First Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the First Term Loan Due 2034 totaled $0.1 million for both the three months ended September 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the First Term Loan Due 2034 totaled $0.3 million and $0.4 million for the nine months ended September 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a payment reserve account held by Veritex, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type.

Second Term Loan Due 2034 (In Default). LRM has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender. The loan agreement is for a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”). The Second Term Loan Due 2034 matures in December 2034, has a current monthly payment of principal and interest of $0.1 million, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use 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 Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LRM was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the Second Term Loan Due 2034. The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

27

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the Second Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.05 million and $0.05 million for the three months ended September 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.1 million and $0.1 million for the nine months ended September 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million, the funds of which were used to purchase idle refinery equipment for refurbishment and use at the Nixon Facility. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type.

Notre Dame Debt (In Default). LE entered a loan with Notre Dame Investors, Inc. as evidenced by a promissory note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). Pursuant to a Sixth Amendment to the Notre Dame Debt, entered on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended to increase the principal amount by $3.7 million (the “Additional Principal”). The Additional Principal was used to make payments to GEL to reduce the balance of the Final Arbitration Award in the amount of $3.6 million in accordance with the GEL Letter Agreement. Interest on the principal accrues at a rate of 16.00%. The Notre Dame Debt matured in January 2018, however, pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate its right to payments, as well as any security interest and liens on the Nixon Facility, in favor of Veritex as holder of the First Term Loan Due 2034.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt.

Capital Leases.

Boiler Equipment Lease. In 2014, LRM entered a 36-month build-to-suit capital lease for the purchase two new boilers for the Nixon Facility. One of the boilers was placed in service during the second quarter of 2017. The other boiler remains in construction in progress. The lease was paid off during the three months ended March 31, 2018.

Crane Lease. In January 2018, LE entered a 24-month capital lease for the purchase of a 20-ton crane for use at the Nixon Facility. The lease requires a negligible monthly payment and matures in January 2020.

28

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

A summary of equipment held under long-term capital leases as of the dates indicated follows:

	September 30,	December 31,
	2018	2017
	(in thousands)
Crane	$94	$-
Less: accumulated depreciation	(10)	-
	$84	$-

(12) Asset Retirement Obligations

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. We depreciate the amount added to property and equipment and recognize accretion expense relating to the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

Changes to our ARO liability for the periods indicated were as follows:

	September 30,	December 31,
	2018	2017
	(in thousands)
Asset retirement obligations, at the beginning of the period	$2,315	$2,028
Liabilities settled	(1)	-
Accretion expense	205	287
	2,519	2,315
Less: asset retirement obligations, current portion	(2,519)	(2,315)
Long-term asset retirement obligations, at the end of the period	$-	$-

(13) Treasury Stock

At September 30, 2018 and December 31, 2017, we had 0 shares of treasury stock. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

29

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

(14) 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 our cash balances at financial institutions located in Houston, Texas. In the U.S., the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. At September 30, 2018 and December 31, 2017, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $1.2 million and $1.6 million, respectively.

Key Supplier.

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

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

For the three months ended September 30, 2018, we had 4 customers that accounted for approximately 94% of refinery operations revenue. LEH, a related party, was 1 of these 4 significant customers and accounted for approximately 29% of refinery operations revenue. At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable. LEH represented approximately $0 in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

For the three months ended September 30, 2017, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 32% of our refined petroleum product sales.  At September 30, 2017, these 4 customers represented approximately $1.5 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

For the nine months ended September 30, 2018, we had 4 customers that accounted for approximately 90% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 29% of our refined petroleum product sales.  At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable.  LEH represented approximately $0 in accounts receivable.

For the nine months ended September 30, 2017, we had 3 customers that accounted for approximately 67% of our refined petroleum product sales.  LEH was 1 of these 3 significant customers and accounted for approximately 34% of our refined petroleum product sales.  At September 30, 2017, these 3 customers represented approximately $1.2 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

30

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

Refined Petroleum Product Sales. Our refined petroleum products are primarily sold in the U.S. However, with the opening of the Mexican diesel market to private companies, we occasionally sell low-sulfur diesel to customers that export to Mexico. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
LPG mix	$-	0.0%	$-	0.0%	$3	0.0%	$121	0.1%
Naphtha	24,127	25.5%	14,266	21.6%	64,093	25.2%	41,283	24.9%
Jet fuel	27,299	28.9%	20,803	31.5%	73,415	28.9%	56,361	32.8%
HOBM	21,735	23.0%	17,011	25.7%	60,594	23.8%	38,580	19.9%
AGO	21,307	22.6%	14,053	21.2%	56,140	22.1%	38,323	22.3%
	$94,468	100.0%	$66,133	100.0%	$254,245	100.0%	$174,668	100.0%

(15) Leases

BDSC leases our principal office space in Houston, Texas under a 2006 lease agreement. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that extended the lease period by sixty-eight (68) months expiring on August 31, 2023. Under the Lease Amendment, our base rent for 6,489 square feet is $0.01 million per month. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For both the three months ended September 30, 2018 and 2017, rent expense totaled $0.03 million. For both the nine months ended September 30, 2018 and 2017, rent expense totaled $0.1 million.

(16) Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The principal element of the Tax Cuts and Jobs Act relevant to our financial statements is a reduction in the U.S. federal corporate tax rate from 34% to 21%, effective January 1, 2018. Other provisions of the Tax Cuts and Jobs Act did not have a significant impact on our financial statements for the three and nine months ended September 30, 2018.

For the three months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.04 million and $0, respectively. For the nine months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.2 million and $0, respectively.

The provision for income tax benefit (expense) as of the dates indicated consisted of the following:

	September 30,	December 31,
	2018	2017
	(in thousands)
Current
Federal	$108	$-
State	43	-
Deferred
Impact of change in enacted tax rates	-	(6,654)
Change in valuation allowance	109	6,654
Total provision for income taxes	$260	$-

31

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to Alternative Minimum Tax credits made refundable by the Tax Cuts and Jobs Act. In 2017, our effective tax rate differed from the U.S. federal statutory rate primarily due to re-measuring deferred income taxes at the new statutory tax rate and the related change of the valuation allowance over our deferred tax assets. 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. This had no impact on our net deferred tax assets.

The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross profit rather than on its net income, certain aspects of TMT make it like an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. For the three and nine months ended September 30, 2018 and 2017, we recognized income relating to state income tax of $0.04 million and $0, respectively.

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

	September 30,	December 31,
	2018	2017
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$11,814	$9,767
Accrued arbitration award payable	3,048	4,122
Start-up costs (crude oil and condensate processing facility)	699	763
Asset retirement obligations liability/deferred revenue	6	495
AMT credit and other	15	217
Total deferred tax assets	14,033	15,365
Deferred tax liabilities:
Basis differences in property and equipment	(4,936)	(4,415)
Total deferred tax liabilities	(4,936)	(4,415)
	9,097	10,950
Valuation allowance	(10,538)	(10,950)
Deferred tax assets, net	$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 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 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.

32

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

 

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, 2016	$9,614	$23,562	$33,176
Net operating losses	-	6,656	6,656
Balance at December 31, 2017	$9,614	$30,218	$39,832
Net operating losses	-	9,747	9,747
Balance at September 30, 2018	$9,614	$39,965	$49,579

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 September 30, 2018 and December 31, 2017, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2018 and December 31, 2017.

(17) Earnings Per Share

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(in thousands, except share and
	per share amounts)
Net income (loss)	$(937)	$3,946	$748	$(23,298)
Basic and diluted income (loss) per share	$(0.09)	$0.36	$0.07	$(2.19)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,925,513	10,818,371	10,925,513	10,644,654

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 the three and nine months ended September 30, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

33

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

(18) Commitments and Contingencies

Legal Matters.

Final Arbitration Award and Settlement Agreement. See “Note (1) Organization – Going Concern – Final Arbitration Award and Settlement Agreement” and "Part II, Item 1. Legal Proceedings” for additional disclosures related to the Final Arbitration Award and the Settlement Agreement.

Veritex Secured Loan Agreement Event of Default. See “Note (1) Organization – Going Concern – Veritex Secured Loan Agreement Event of Default” and “Note (11) Long-Term Debt, Net” for disclosures related to defaults under secured loan agreements.

Other Legal Matters. From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

Amended and Restated Operating Agreement. See “Note (9) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.

FLNG Easements. BDPL and FLNG were parties to a Pipeline Easement dated November 5, 2005 (the “FLNG Pipeline Easement”) and the FLNG Master Easement Agreement (together with the FLNG Pipeline Easement, the “FLNG Easements”). The FLNG Easements provided FLNG and its affiliates: (i) a pipeline easement and right of way across BDPL-owned property to certain property owned by FLNG and (ii) rights of ingress and egress across BDPL-owned property to the property owned by FLNG. Under the FLNG Easements, FLNG made payments to us in the amount of $0.5 million each year. The FLNG Easements were terminated in February 2017.

Financing Agreements. See “Note (11) Long-Term Debt, Net” for additional disclosures related to financing agreements.

Guarantees. LEH and Jonathan Carroll have provided guarantees on certain Blue Dolphin-related long-term debt. The maximum amount of any guarantee is reduced as payments are made. See “Note (11) Long-Term Debt, Net” for additional disclosures related to guarantees.

Health, Safety and Environmental Matters. All our operations and properties 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 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 greenhouse gas 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 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 and completion of petroleum storage tanks.

Supplemental Pipeline Bonds. In a letter dated March 30, 2018, the Bureau of Ocean Energy Management (the “BOEM”) ordered BDPL to provide additional supplemental bonds or acceptable financial assurance of approximately $4.8 million (the “Separate Orders”) within sixty (60) calendar days of receipt of the letter. The Separate Orders relate to five (5) existing pipeline rights-of-way. BOEM issued an Incident of Noncompliance (“INC”) for each Separate Order dated June 8, 2018 and received by BDPL on June 11, 2018. BOEM asserts that the INCs authorize BOEM to impose financial penalties on BDPL if it does not comply with the Separate Orders within twenty (20) days. BOEM asserts that potential penalties accrue for each day BDPL failed to comply after June 28, 2018.  BDPL appealed the INCs on August 8, 2018 and its deadline for filing a Statement of Reasons with BOEM has been extended by the Interior Board of Land Appeals (the “IBLA”). BDPL’s appeal of the Separate Orders was denied by the IBLA on October 18, 2018. BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance in accordance with the Separate Orders, or of BOEM’s authority to impose financial penalties.

34

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Notes to Consolidated Financial Statements (Continued)

BDPL has initiated settlement discussions with BOEM to resolve the Separate Orders and the INCs. There can be no assurance that BOEM will: (i) accept a proposal for a reduced amount of supplemental financial assurance, (ii) not require additional supplemental pipeline bonds related to BDPL’s existing pipeline rights-of-way, and/or (iii) not impose penalties under the INCs. As a result, we are unable to predict the outcome of the discussions with BOEM or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded a liability on our consolidated balance sheet as of September 30, 2018. As of September 30, 2018 and December 31, 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition.

Remainder of Page Intentionally Left Blank

35

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

ITEM 2.  

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

In this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018 (the Quarterly Report”), references to “Blue Dolphin,” “we,” “us” and “our” are to Blue Dolphin Energy Company and its subsidiaries, unless otherwise indicated or the context otherwise requires. You should read the following discussion together with the financial statements and the related notes included elsewhere in this Quarterly Report, as well as with the risk factors, financial statements, and related notes included thereto in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 (the “Annual Report”), in our Quarterly Report on Form 10-Q for the period ended March 31, 2018, and in our Quarterly Report on Form 10-Q for the period ended June 30, 2018.  

Forward Looking Statements

Certain statements included in this Quarterly Report, including in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1935.  Forward-looking statements represent management’s beliefs and assumptions based on currently available information. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources, access to supplies of crude oil and condensate, commitments and contingencies, and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future,” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations regarding future events, results, or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized, or materially affect our financial condition, results of operations and cash flows.  Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all these factors, they include, among others, the following and other factors described under the heading “Risk Factors” in the Annual Report, our Quarterly Report on Form 10-Q for the period ended March 31, 2018, our Quarterly Report on Form 10-Q for the period ended June 30, 2018, and this Quarterly Report:

Risks Related to Our Business and Industry

●

Failure to meet the terms and conditions set forth in the Settlement Agreement with GEL, including but not limited to securing the Settlement Financing (See “Part I. Financial Information, Item 1. Financial Statements, Notes to Consolidated Financial Statements – Note (1) Organization – Going Concern – Final Arbitration Award and Settlement Agreement” for disclosures related to the Settlement Agreement).

●

Inadequate liquidity to sustain operations due to the unfavorable outcome in the arbitration of the contract-related dispute with GEL, net losses, working capital deficits, and other factors, including crude supply issues tied to access to capital and financial covenant defaults in secured loan agreements, any of which could have a material adverse effect on us.

●

Dangers inherent in oil and gas operations that could cause disruptions and expose us to potentially significant losses, costs or liabilities and reduce our liquidity.

●

Geographic concentration of our assets, which creates a significant exposure to the risks of the regional economy.

●

Competition from companies having greater financial and other resources.

●

Laws and regulations regarding personnel and process safety, as well as environmental, health, and safety, for which failure to comply may result in substantial fines, criminal sanctions, permit revocations, injunctions, facility shutdowns, and/or significant capital expenditures.

●

Insurance coverage that may be inadequate or expensive.

36

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

●

Failure to comply with certain financial covenants related to certain secured loan agreements.

●

Our ability to use net operating loss (“NOL”) carryforwards to offset future taxable income for U.S. federal income tax purposes, which are subject to limitation.

●

Terrorist attacks, cyber-attacks, threats of war, or actual war may negatively affect our operations, financial condition, results of operations, and cash flows.

Risks Related to Our Refinery Operations Business Segment

●

A determination by management that there is, and the report of our independent registered public accounting firm that expresses, substantial doubt about our ability to continue as a going concern.

●

Volatility of refining margins.

●

Volatility of crude oil, other feedstocks, refined petroleum products, and fuel and utility services prices.

●

Our ability to acquire sufficient levels of crude oil on favorable terms to operate the Nixon Facility.

●

Refinery downtime, which would result in lost margin opportunity, increased maintenance costs, increased inventory, and a reduction in cash available for payment of our obligations and to which we are particularly vulnerable because all our refining operations are conducted at a single facility.

●

Capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

●

Our dependence on LEH and its affiliates for financing and management of our properties.

●

Related party transactions with LEH and its affiliates (including Jonathan Carroll and Ingleside), which may cause conflicts of interest.

●

Loss of executive officers or key employees, as well as a shortage of skilled labor or disruptions in our labor force, which may make it difficult to maintain productivity.

●

Failure to grow or maintain the market share for our refined petroleum products.

●

Our reliance on third parties for the transportation of crude oil and condensate into and refined petroleum products out of the Nixon Facility.

●

Interruptions in the supply of crude oil and condensate sourced in the Eagle Ford Shale.

●

Changes in the supply/demand balance in the Eagle Ford Shale that could result in lower margins.

●

Loss of market share by a key customer or consolidation among our customer base.

●

Regulation of greenhouse gas emissions, which could increase our operational costs and reduce demand for our products.

Risks Related to Our Pipelines and Oil and Gas Properties

●

Failure to meet the requirements of BOEM’s Separate Orders to provide additional supplemental bonds or acceptable financial assurance, which would significantly impact our liquidity and financial condition.

●

More stringent regulatory requirements related to asset retirement obligations (“AROs”), which could significantly increase our estimated future AROs.

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

Going Concern

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

Operating Risks

See “Part I, Item 1. Financial Statements – Note (1) Organization – Operating Risks” regarding factors that have negatively impacted execution of our business plan.

37

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Company Overview

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

Major Influences on Results of Operations

Refinery Operations

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

Price Differentials per Bbl

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

●

Domestic and foreign market conditions, political affairs, and economic developments;

●

Import supply levels and export opportunities;

●

Existing domestic inventory levels;

●

Operating and production levels of competing refineries;

●

Expansion and/or upgrades of competitors’ facilities;

●

Governmental regulations (e.g., mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles);

●

Weather conditions;

●

Availability of and access to transportation infrastructure;

●

Availability of competing fuels (e.g., renewables); and

●

Seasonal fluctuations.

Product Slate

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

Refinery Downtime

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

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

38

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Tolling and Terminaling Operations

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

●

price (in terms of storage fees) and available capacity;

●

industry factors including changes in the prices of petroleum products that affect demand for storage services; and

●

utilization rates of our competitors (local demand).

Key Relationships

Relationship with LEH

Blue Dolphin and certain of its subsidiaries are currently party to a variety of agreements with LEH. Related party agreements with LEH include: (i) an Amended and Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL, (iv) an Amended and Restated Promissory Note with Blue Dolphin, and (v) a Debt Assumption Agreement with LE. In addition, we currently rely on advances from LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. There can be no assurances that LEH and its affiliates will continue to fund our working capital requirements. (See “Part I, Item 1. Financial Statements – Note (9) Related Party Transactions” for additional disclosures related to agreements that we have in place with LEH and its affiliates.)

Relationship with Crude Supplier

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

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

Results of Operations

Consolidated Results

Three Months Ended September 30, 2018 (the “Current Three-Month Period”) Compared to September 30, 2017 (the “Prior Three-Month Period”).

Total Revenue from Operations. For the Current Three-Month Period, we had total revenue from operations of $95.5 million compared to total revenue from operations of $66.9 million for the Prior Three-Month Period, an increase of approximately 43%. Approximately 99% of our revenue from operations is derived from refinery operations. For the Current Three-Month Period compared to the Prior Three-Month Period, 89% of the increase in refinery operations revenue was due to higher product pricing while 11% was due to increased sales volume. For the same period, tolling and terminaling revenue increased approximately 40% as a result of increased storage fees under renewed customer agreements.

39

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Cost of Sales. Cost of sales was $93.2 million for the Current Three-Month Period compared to $58.8 million for the Prior Three-Month Period. The approximate 59% increase in cost of sales in the Current Three-Month Period compared to the Prior Three-Month Period was the result of higher crude oil prices and slightly increased sales volume.

Gross Profit / Gross Margin. For the Current Three-Month Period, gross profit totaled $2.3 million, or approximately 2%, compared to gross profit of $8.1 million, or approximately 12%, for the Prior Three-Month Period. The significant decrease in gross profit between the periods primarily related to less favorable margins for refined petroleum products.

Refinery Operating Expenses. We recorded refinery operating expenses of $1.1 million, or $0.89 per bbl, in the Current Three-Month Period compared to $1.8 million, or $1.53 per bbl, in the Prior Three-Month Period, a decrease of approximately 38%. The $0.7 million, or $0.64 per bbl, decrease in refinery operating expenses between the periods was the result of lower refinery operating expenses under the Amended and Restated Operating Agreement and management’s efforts to reduce spending. (See “Part I, Item 1. Financial Statements – Note (9) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement, including a breakdown of expenses and fees.)

General and Administrative Expenses. We incurred general and administrative expenses of $0.9 million in the Current Three-Month Period compared to $1.2 million in the Prior Three-Month Period. The approximate 25% decrease in general and administrative expenses between the periods primarily related to decreased legal expenses.

Other Income (Expense). Total other income (expense) was an expense of $0.7 million in the Current Three-Month Period compared to expense of $0.6 million in the Prior Three-Month Period, which was relatively flat.

Net Income (Loss). For the Current Three-Month Period, we reported a net loss of $0.9 million, or a loss of $0.09 per share, compared to net income of $3.9 million, or income of $0.36 per share, for the Prior Three-Month Period. Net loss for the Current Three-Month Period was primarily the result of lower and sometimes negative margins on refined petroleum products, while net income for the Prior Three-Month Period was primarily the result of favorable margins for refined petroleum products.

Nine Months Ended September 30, 2018 (the “Current Nine-Month Period”) Compared to September 30, 2017 (the “Prior Nine-Month Period”).

Total Revenue from Operations. For the Current Nine-Month Period, we had total revenue from operations of $256.9 million compared to total revenue from operations of $176.8 million for the Prior Nine-Month Period, an increase of approximately 43%. Approximately 99% of our revenue from operations is derived from refinery operations. For the Current Nine-Month Period compared to the Prior Nine-Month Period, 87% of the increase in refinery operations revenue was due to higher product pricing while 13% was due to increased sales volume. For the same period, tolling and terminaling revenue increased approximately 22% as a result of increased storage fees under renewed customer agreements.

Cost of Sales. Cost of sales was $245.8 million for the Current Nine-Month Period compared to $165.2 million for the Prior Nine-Month Period. The nearly 49% increase in cost of sales in the Current Nine-Month Period compared to the Prior Nine-Month Period was the result of higher crude oil prices and slightly increased sales volume.

Gross Profit / Gross Margin. For the Current Nine-Month Period, gross profit totaled $11.1 million, or 4%, compared to gross profit of $11.7 million, or nearly 7%, for the Prior Nine-Month Period. The decrease in gross profit between the periods primarily related to less favorable margins on refined petroleum products.

Refinery Operating Expenses. We recorded refinery operating expenses of $4.4 million, or $1.28 per bbl, in the Current Nine-Month Period compared to $6.2 million, or $1.93 per bbl, in the Prior Nine-Month Period, a decrease of nearly 30%. The $1.8 million, or $0.65 per bbl, decrease in refinery operating expenses between the periods was the result of lower refinery operating expenses in the Current Nine-Month Period, a general cost restructure under the Amended and Restated Operating Agreement in the Prior Nine-Month Period, and management’s efforts to reduce overall spending. (See “Part I, Item 1. Financial Statements – Note (9) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement, including a breakdown of expenses and fees.)

40

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

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

General and Administrative Expenses. We incurred general and administrative expenses of $2.3 million in the Current Nine-Month Period compared to $2.9 million in the Prior Nine-Month Period. For the Current Nine-Month Period compared to the Prior Nine-Month Period, the approximate 20% decrease in general and administrative expenses primarily related to lower legal fees.

Depletion, Depreciation and Amortization. We recorded depletion, depreciation and amortization expenses of $1.4 million in the Current Nine-Month Period compared to $1.4 million in the Prior Nine-Month Period, which was flat.

Other Income (Expense). Total other income (expense) was an expense of $2.2 million in the Current Nine-Month Period compared to income of $0.2 million in the Prior Nine-Month Period. The Prior Nine-Month Period included a one-time gain on the sale of property.

Income Tax Expense. We recognized an income tax benefit of $0.3 million in the Current Nine-Month Period compared to an income tax expense of $0 in the Prior Nine-Month Period. Income tax benefit in the Current Nine-Month Period primarily relates to a refundable AMT paid in prior periods. (See “Part I, Item 1. Financial Statements – Note (16) Income Taxes” for additional disclosures related to income taxes.)

Net Income (Loss). For the Current Nine-Month Period, we reported income of $0.7 million, or income of $0.07 per share, compared to a net loss of $23.3 million, or loss of $2.19 per share, for the Prior Nine-Month Period. The Prior Nine-Month Period included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million in arbitration award and associated fees and represented an expense of $2.29 per share.  Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.26 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis declined $0.03 per share between the periods, which was primarily the result of less favorable margins for refined petroleum products.

Non-GAAP Financial Measures

To supplement our consolidated results, management uses refining gross profit per bbl and EBITDA, non-GAAP financial measures, to help investors evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. Refining gross profit per bbl and EBITDA are reconciled to GAAP-based results below. Refining gross profit per bbl and EBITDA should not be considered an alternative for GAAP results. Refining gross profit per bbl and EBITDA are provided to enhance an overall understanding of our financial performance for the applicable periods and are indicators that management believes are relevant and useful. Refining gross profit per bbl and EBITDA may differ from similar calculations used by other companies within the petroleum industry, thereby limiting its usefulness as a comparative measure. (See “Part I, Item 1. Financial Statements” for comparative GAAP results.)

Refining Gross Profit per Bbl – For the Current Three-Month Period, refining gross profit per bbl was $1.07 compared to $6.46 per bbl for the Prior Three-Month Period, reflecting a decrease of $5.39. The significant decrease between the periods primarily related to less favorable margins for refined petroleum products in the Current Three-Month Period compared to the Prior Three-Month Period. (See “Glossary of Selected Energy and Financial Terms” in this Quarterly Report for the definition of gross margin per bbl.)

For the Current Nine-Month Period, refining gross profit per bbl was $2.54 compared to $3.02 per bbl for the Prior Nine-Month Period, reflecting a decrease of $0.48. The decrease between the periods primarily related to unfavorable margins for refined petroleum products in the Current Nine-Month Period compared to the Prior Nine-Month Period.

41

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

EBITDA – EBITDA for the periods indicated was as follows:

●

Refinery Operations. EBITDA for refinery operations was negative at $0.4 million for the Current Three-Month Period compared to $5.4 million for the Prior Three-Month Period. The $5.0 million decrease between the periods primarily related to less favorable margins for refined petroleum products in the Current Three-Month Period.

For the Current Nine-Month Period, EBITDA for refinery operations was positive at $2.8 million compared to a loss of $20.9 million for the Prior Nine-Month Period. The improvement between the periods was primarily the result of favorable margins for refined petroleum products. Including the Final Arbitration Award, EBITDA for refinery operations improved $23.7 million between the periods. Excluding the Final Arbitration Award, EBITDA for refinery operations decreased $0.7 million between the periods primarily as a result of less favorable margins for refined petroleum products.

●

Tolling and Terminaling. EBITDA for tolling and terminaling operations was positive at $1.3 million for the Current Three-Month Period. EBITDA for tolling and terminaling operations was also positive at $2.8 million for the Current Nine-Month Period. We did not report tolling and terminaling operations as a separate business segment in 2017.

	Three Months Ended September 30,
	2018				2017
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Corporate
	Operations	Terminaling	& Other	Total	Operations	& Other	Total
Net revenues (excluding intercompany fees and sales)	$94,468	$1,075	$-	$95,543	$66,899	$-	$66,899
Intercompany fees and sales	(873)	873	-	-	-	-	-
Operation costs and expenses(1)
Cost of materials and other	(92,571)	-	-	(92,571)	(58,786)	-	(58,786)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)	(1,085)	(624)	(94)	(1,803)	(1,758)	(140)	(1,898)
Segment contribution margin	$(61)	$1,324	$(94)	$1,169	$6,355	$(140)	$6,215
General and administrative expenses	(375)	(65)	(489)	(929)	(913)	(327)	(1,240)
EBITDA	$(436)	$1,259	$(583)	$240	$5,442	$(467)	$4,975
Depreciation and amortization	(432)	(46)	-	(478)	(452)	(3)	(455)
Interest and other non-operating expenses, net				(742)			(574)
Income (loss) before income taxes				(980)			3,946
Income tax benefit				43			-
Net income (loss)				$(937)			$3,946

(1)  Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

42

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

 

	Nine Months Ended September 30,
	2018				2017
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Corporate
	Operations	Terminaling	& Other	Total	Operations	& Other	Total
Net revenues (excluding intercompany fees and sales)	$254,245	$2,659	$-	$256,904	$176,842	$-	$176,842
Intercompany fees and sales	(2,419)	2,419	-	-	-	-	-
Operation costs and expenses(1)
Cost of materials and other	(244,380)	-	-	(244,380)	(189,525)	-	(189,525)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)	(3,698)	(2,092)	(338)	(6,128)	(6,223)	(399)	(6,622)
Segment contribution margin	$3,748	$2,986	$(338)	$6,396	$(18,906)	$(399)	$(19,305)
General and administrative expenses	(929)	(156)	(1,192)	(2,277)	(1,960)	(894)	(2,854)
EBITDA	$2,819	$2,830	$(1,530)	$4,119	$(20,866)	$(1,293)	$(22,159)
Depreciation and amortization	(1,258)	(138)	-	(1,396)	(1,348)	(8)	(1,356)
Interest and other non-operating income (expenses)(2)				(2,235)			217
Income (loss) before income taxes				488			(23,298)
Income tax benefit				260			-
Net income (loss)				$748			$(23,298)

(1)

Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

(2)

Reflects FLNG easement revenue in 2017. See “Part I, Item 1. – Notes to Consolidated Financial Statements – Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

Remainder of Page Intentionally Left Blank

43

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refinery Operations Throughput and Production Data

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(in thousands, except uptime data
	and percent amounts)
Calendar Days	92	92	273	273
Refinery downtime	(3)	(3)	(24)	(17)
Operating Days	89	89	249	256
Total refinery throughput (bbls)	1,220	1,145	3,411	3,228
Operating days:
bpd	14	13	14	13
Capacity utilization rate	91.4%	85.8%	91.3%	84.1%
Calendar days:
bpd	13	12	12	12
Capacity utilization rate	88.4%	83.0%	83.3%	78.8%
Total refinery production (bbls)	1,184	1,111	3,314	3,127
Operating days:
bpd	13	12	13	12
Capacity utilization rate	88.7%	83.2%	88.7%	81.4%
Calendar days:
bpd	13	12	12	11
Capacity utilization rate	85.8%	80.5%	80.9%	76.4%

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

In the Current Three-Month Period, the refinery experienced three (3) days of downtime primarily related to needed repairs and maintenance. In the Prior Three-Month Period, the refinery experienced three (3) days of downtime related to Hurricane Harvey. For the Current Three-Month Period compared to the Prior Three-Month Period, total refinery throughput bbls and total refinery production bbls increased nominally.

In the Current Nine-Month Period, the refinery experienced twenty-four (24) days of downtime primarily related to repair and maintenance of the naphtha stabilizer unit and short maintenance turnarounds scheduled in January and March of 2018. In the Prior Nine-Month Period, the refinery experienced seventeen (17) days of downtime primarily due to a contract-related dispute with GEL and Hurricane Harvey. For the Current Nine-Month Period compared to the Prior Nine-Month Period, total refinery throughput bbls and total refinery production bbls increased nominally despite the refinery being down more days in the Current Nine-Month Period.

Typically, in the summer months refinery throughput volumes at the Nixon Facility are negatively impacted by the extreme Texas heat. In the three and nine month periods ended September 30, 2018, the Nixon Facility was positively impacted by the use of a cooling unit. The cooling unit allowed the refinery to run more bbls per day, resulting in increased refinery throughput and production volumes in the periods despite refinery downtime. The cooling unit was not used during the three and nine month periods ended September 30, 2017.

Refined Petroleum Product Sales Summary.

See “Part I, Item 1. Financial Statements - Note (14) Concentration of Risk” for a discussion of refined petroleum product sales.

44

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Liquidity and Capital Resources

Overview.

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

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

We are continuing aggressive actions to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability; however, our results of operations and liquidity are highly dependent upon the margins that we receive for our refined petroleum products. The per bbl price difference between crude oil and condensate (input) and refined petroleum products (output), is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. For example, for the Current Three-Month Period, our financial results were negatively impacted by market conditions while our financial results for the Prior Three-Month Period were positively impacted by market conditions. There can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, that we will be able to obtain additional financing on commercially reasonable terms or at all, or that margins for refined petroleum products will be favorable. Further, if Veritex does not approve the Settlement or the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

Crude Oil and Condensate Supply.

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

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

Remainder of Page Intentionally Left Blank

45

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Cash Flow.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
	(in thousands)
Beginning cash, cash equivalents, and restricted cash	$2,012	$2,110	$2,146	$6,083
Cash flow from operations
Adjusted profit (loss) from operations	(366)	4,505	2,229	(21,600)
Change in assets and current liabilities	400	(5,673)	(1,075)	15,464
Total cash flow from operations	34	(1,168)	1,154	(6,136)
Cash inflows (outflows)
Proceeds from issuance of debt	-	3,678	-	3,678
Payments on debt	(248)	(265)	(723)	(1,120)
Net activity on related-party debt	472	(2,289)	924	968
Capital expenditures	(595)	(370)	(1,826)	(1,777)
Total cash inflows (outflows)	(371)	754	(1,625)	1,749
Total change in cash flows	(337)	(414)	(471)	(4,387)
Ending cash, cash equivalents, and restricted cash	$1,675	$1,696	$1,675	$1,696

For the Current Three-Month Period, we experienced cash flow from operations of $0.03 million compared to negative cash flow from operations of $1.2 million for the Prior Three-Month Period. The $1.1 million improvement in cash flow from operations between the periods was primarily the result of $3.7 million in payments related to the Final Arbitration Award during the Prior Three-Month Period compared to only $1.0 million in the Current Three-Month Period. For the Current Nine-Month Period, we experienced cash flow from operations of $1.2 million compared to negative cash flow from operations of $6.1 million for the Prior Six-Month Period. The $7.3 million improvement in cash flow from operations between the periods was primarily the result of improved operating income.

Working Capital.

We had a working capital deficit of $71.0 million at September 30, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $29.5 million at September 30, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017.

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

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

46

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Capital Spending.

Capital improvements primarily relate to construction of new petroleum storage tanks to add to existing petroleum storage capacity. Since 2015, the Nixon Facility has been undergoing a capital improvement expansion project to significantly increase petroleum storage capacity.  Increased petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 30,000 bpd, and (iii) provides an opportunity to generate additional tolling and terminaling revenue. When the expansion project is complete, petroleum storage capacity at the Nixon Facility will exceed 1.2 million bbls, an increase of more than 0.9 million bbls. Capital expenditures at the Nixon Facility are being funded by working capital and Veritex through long-term debt that was secured in 2015. Available funds under these loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. See “Part I, Item 1. Financial Statements – Note (11) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

Contractual Obligations.

Related Party. See “Part I, Item 1. Financial Statements – Note (9) Related Party Transactions” for a summary of the agreements we have in place with related parties.

Long-Term Debt. See "Part I, Item 1. Financial Statements - Note (11) Long-Term Debt, Net" for a summary of our long-term debt.

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

Supplemental Pipeline Bonds. See “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies – Supplemental Pipeline Bonds” for a discussion of supplemental pipeline bonding requirements.

Indebtedness.

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

	September 30,	December 31,
	2018	2017
	(in thousands)
First Term Loan Due 2034 (in default)	$22,663	$23,199
Second Term Loan Due 2034 (in default)	9,344	9,502
Notre Dame Debt (in default)	4,978	4,978
BDPL Loan Agreement (in default)	4,000	4,000
March Ingleside Note	1,263	1,169
March Carroll Note	966	439
Capital Leases	51	-
June LEH Note	303	-
	43,568	43,287
Less: Current portion of long-term debt, net	(41,520)	(39,544)
Less: Unamoritized debt issue costs	(2,038)	(2,135)
	$10	$1,608

Principal payments on long-term debt totaled $0.2 million in the Current Three-Month Period compared to $0.3 million in the Prior Three-Month Period. Payments on long-term debt totaled $0.7 million in the Current Nine-Month Period compared to $1.1 million in the Prior Nine-Month Period.

47

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

As described elsewhere in this Quarterly Report, Veritex notified obligors that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034 and Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the secured loan agreements. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under the secured loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under the loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the secured loan agreements considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws.

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

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

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies

Long-Lived Assets.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented.

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

48

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

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

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

Revenue Recognition.

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

Refinery Operations Revenue. Revenue from the sale of refined petroleum products is recognized when the product is sold to a customer in fulfillment of performance obligations. Each barrel of refined petroleum product, or other unit of measure, 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 in accordance with the terms of the respective sales agreement. We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant. Transportation, shipping and handling costs incurred are included in cost of sales. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

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

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

Inventory.

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

49

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Asset Retirement Obligations.

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

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

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating or disposing of our offshore platform, pipeline systems and related onshore facilities, as well as plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.

Income Taxes.

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any NOL carryforwards. At September 30, 2018 and December 31, 2017, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2018 and December 31, 2017.

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

See “Part I, Item 1. Financial Statements - Note (16) Income Taxes” for further information related to income taxes.

50

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Recently Adopted Accounting Guidance

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

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

New Pronouncements Issued, Not Yet Effective

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

ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In July 2018, FASB issued ASUs 2018-11 and 2018-10. ASU 2018-11 provides entities with relief from the costs of implementing certain aspects of ASU 2016-02 (codified as ASC 842). Specifically, under the amendments in ASU 2018-11: (i) Entities may elect not to recast the comparative periods presented when transitioning to ASC 842 (Issue 1), and (ii) Lessors may elect not to separate lease and non-lease components when certain conditions are met (Issue 2). ASU 2018-10 made 16 separate amendments to ASC 842. For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in: (i) the recognition of a liability to make lease payments and a right-to-use asset representing our right to use the underlying asset on our consolidated balance sheets and (ii) the recognition of an expense on our consolidated statements of operations each month as we amortize the right-to-use asset.

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

ASU 2018-07, Compensation – Stock Compensation (Topic 718). In June 2018, FASB issued ASU 2018-07. This guidance expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The amendments in ASU 2018-07 are effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

51

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/18
Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

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

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

Remainder of Page Intentionally Left Blank

52

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision of, and with the participation of our management, including our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial 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 Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report. Based on our evaluation, our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial 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.

Changes in Internal Control over Financial Reporting

Management concluded that our internal control over financial reporting was effective as of December 31, 2017. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three and nine months ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. (See “Part I, Item 4. Controls and Procedures – Evaluation of Disclosure Controls and Procedures” of this Quarterly Report for a discussion related to controls and procedures.)

53

PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Final Arbitration Award

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

Other Legal Matters

From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our Annual Report. These risks and uncertainties could materially and adversely affect our business, financial condition and results of operations. Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business. There have been no material changes in our assessment of our risk factors from those set forth in our Annual Report.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

54

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

See “Part I, Item. 1. Financial Statements – Note (11) Long-Term Debt, Net” for disclosures related to defaults on our debt.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

Exhibits Index

No.	Description
10.1	Settlement Agreement, dated as of July 20, 2018, by and among Lazarus Energy, LLC, Blue Dolphin Energy Company, Lazarus Energy Holdings, LLC, Nixon Product Storage, LLC, Carroll & Carroll Financial Holdings, L.P., and Jonathan Carroll.
10.2*	First Amendment to the Settlement Agreement, dated as of October 17, 2018, by and among Lazarus Energy, LLC, Blue Dolphin Energy Company, Lazarus Energy Holdings, LLC, Nixon Product Storage, LLC, Carroll & Carroll Financial Holdings, L.P., and Jonathan Carroll.
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.
31.2*	Tommy L. Byrd 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.
32.2*	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
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.

*            

Filed herewith.

55

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/18

SIGNATURES

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

	BLUE DOLPHIN ENERGY COMPANY
	(Registrant)
November 14, 2018	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)

November 14, 2018	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

56

EX-10.2

Exhibit 10.2 

FIRST AMENDMENT TO THE SETTLEMENT AGREEMENT

This First Amendment to the Settlement Agreement (this “First Amendment”), dated as of October 17, 2018, is by and between Lazarus Energy, LLC, a Delaware limited liability company (“Lazarus”); Blue Dolphin Energy Company, a Delaware corporation (“BDEC”); Lazarus Energy Holdings, LLC, a Delaware limited liability company (“LEH”); Nixon Product Storage, LLC, a Delaware limited liability company (“Nixon”); Carroll & Company Financial Holdings, L.P. (“C&C”); Jonathan Carroll (“Carroll” and, together with Lazarus, BDEC, LEH, Nixon, and C&C the “Lazarus Parties”); and GEL Tex Marketing, LLC, a Delaware limited liability company (“GEL Tex”) (each, a “Party” and, collectively, the “Parties”).

RECITALS

WHEREAS, on July 20, 2018, the Parties executed the Settlement Agreement1 in order to provide for a settlement between the Lazarus Parties and GEL Tex regarding the Final Award that resolves the Arbitration and the District Court Action contingent upon the Lazarus Parties obtaining the Settlement Financing to fund a settlement in accordance with the terms of the Settlement Agreement;

WHEREAS, paragraph 15(d) of the Settlement Agreement requires the Lazarus Parties to achieve certain milestones in connection with obtaining the Settlement Financing;

WHEREAS, in order to facilitate the Lazarus Parties’ ongoing negotiations to obtain the Settlement Financing, GEL Tex and the Lazarus Parties hereby agree to amend the Settlement Agreement;

NOW, THEREFORE, in consideration of the foregoing and the mutual covenant and agreements set forth in the Settlement Agreement and this First Amendment, and for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound, agree as follows:

AGREEMENT

1.Paragraph 15(d)(i) of the Settlement Agreement shall be amended and replaced in its entirety and shall now state:

Provide GEL Tex with a copy of the United States Department of Agriculture’s or a bona fide third-party lender’s Commitment of the Settlement Financing by no later than November 15, 2018, unless otherwise extended in writing by GEL Tex;

2.GEL Tex and the Lazarus Parties agree that this First Amendment may be executed in separate parts delivered by electronic means that, taken together, will be deemed to be one instrument. GEL Tex and each Lazarus Party represent and warrant that this First Amendment has

1 All capitalized terms used but not otherwise defined in this First Amendment shall have the meanings given to such terms in the Settlement Agreement.

been approved and authorized by all necessary action and the execution hereof does not violate any agreement to which it is a party.

3.Except as set forth in this First Amendment, the Settlement Agreement is

unaffected and shall continue in full force and effect in accordance with its terms. If there is a conflict between this First Amendment and the Settlement Agreement, the terms of this First Amendment will prevail.

[Signature Pages Follow]

- 2 -

IN WITNESS WHEREOF, the undersigned have caused this First Amendment to the Settlement Agreement to be duly executed and delivered as of the date first set forth above.

GEL TEX MARKETING, LLC

By:	/s/ R.V. DEERE
Name:	Robert V. Deere
Title:	Chief Financial Officer

LAZARUS ENERGY, LLC

By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President

BLUE DOLPHIN ENERGY COMPANY

By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President

LAZARUS ENERGY HOLDINGS, LLC

By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President

NIXON PRODUCT STORAGE, LLC

By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President

CARROLL & COMPANY FINANCIAL HOLDINGS, L.P.

By:	/s/ JONATHAN CARROLL
Name:	Lazarus Financial, LLC
Title:	General Partner

By:	/s/ JONATHAN CARROLL
	Jonathan Carroll

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.   The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;

5.   The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2018	By:	/s/ Jonathan P. Carroll
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.   The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;

5.   The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2018	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2018 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2018	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2018 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2018	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 14, 2018
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Common Stock, Shares Outstanding		10,925,513
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2018

XML

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 24	$ 495
Restricted cash	49	49
Accounts receivable, net	1,669	1,357
Accounts receivable, related party	0	653
Prepaid expenses and other current assets	447	1,207
Deposits	194	129
Inventory	2,627	3,089
Deferred tax assets, net	108	0
Total current assets	5,118	6,979
Total property and equipment, net	65,109	64,597
Restricted cash, noncurrent	1,602	1,602
Surety bonds	230	230
Refundable federal income tax, net	108	0
Total long-term assets	67,049	66,429
TOTAL ASSETS	72,167	73,408
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default	34,988	35,544
Long-term debt, related party, current portion, in default	6,532	4,000
Interest payable, in default	2,734	2,135
Interest payable, related party, in default	1,374	892
Accounts payable	2,617	2,344
Accounts payable, related party	1,378	974
Asset retirement obligations, current portion	2,519	2,315
Accrued expenses and other current liabilities	863	1,160
Accrued arbitration award payable	23,128	27,128
Total current liabilities	76,133	76,492
Long-term liabilities:
Deferred revenues and expenses	10	42
Capital lease obligation, net of current portion	10	0
Long-term debt, related party, net of current portion	0	1,608
Total long-term liabilities	20	1,650
TOTAL LIABILITIES	76,153	78,142
Commitments and contingencies (Note 18)
STOCKHOLDERS' DEFICIT
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,925,513 shares issued at September 30, 2018 and December 31, 2017, respectively)	109	109
Additional paid-in capital	36,907	36,907
Retained earnings (deficit)	(41,002)	(41,750)
TOTAL STOCKHOLDERS' DEFICIT	(3,986)	(4,734)
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$ 72,167	$ 73,408

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Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2018	Dec. 31, 2017
STOCKHOLDERS' DEFICIT
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,925,513	10,925,513
Common stock, shares outstanding	10,925,513	10,925,513

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Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
REVENUE FROM OPERATIONS
Refinery operations	$ 94,468	$ 66,133	$ 254,245	$ 174,668
Tolling and terminaling	1,075	766	2,659	2,174
Total revenue from operations	95,543	66,899	256,904	176,842
COST OF OPERATIONS
Cost of sales	93,195	58,786	245,786	165,185
Refinery operating expenses	1,085	1,758	4,384	6,223
Other operating expenses	33	68	133	183
Arbitration award and associated fees	0	0	0	24,339
General and administrative expenses	929	1,240	2,277	2,854
Depletion, depreciation and amortization	478	455	1,396	1,356
Accretion of asset retirement obligations	61	72	205	216
Total cost of operations	95,781	62,379	254,181	200,356
Income (loss) from operations	(238)	4,520	2,723	(23,514)
OTHER INCOME (EXPENSE)
Easement, interest and other income	18	27	20	410
Interest and other expense	(760)	(601)	(2,255)	(2,028)
Gain on disposal of property	0	0	0	1,834
Total other income (expense)	(742)	(574)	(2,235)	216
Income (loss) before income taxes	(980)	3,946	488	(23,298)
Income tax benefit	43	0	260	0
Net income (loss)	$ (937)	$ 3,946	$ 748	$ (23,298)
Income (loss) per common share:
Basic	$ (0.09)	$ 0.36	$ 0.07	$ (2.19)
Diluted	$ (0.09)	$ 0.36	$ 0.07	$ (2.19)
Weighted average number of common shares outstanding:
Basic	10,925,513	10,818,371	10,925,513	10,644,654
Diluted	10,925,513	10,818,371	10,925,513	10,644,654
Dividends declared per common share outstanding	$ .00	$ .00	$ .00	$ .00

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
OPERATING ACTIVITIES
Net income (loss)	$ (937)	$ 3,946	$ 748	$ (23,298)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization			1,396	1,356
Deferred income tax			(216)	0
Amortization of debt issue costs			96	96
Accretion of asset retirement obligations	61	72	205	216	$ 287
Common stock issued for services			0	30
Changes in operating assets and liabilities
Accounts receivable			(312)	1,395
Accounts receivable, related party			653	101
Prepaid expenses and other current assets			760	(585)
Deposits and other assets			(65)	(25)
Inventory			462	(700)
Accrued arbitration award			(4,000)	27,628
Accounts payable, accrued expenses and other liabilities			1,023	(12,804)
Accounts payable, related party			404	454
Net cash provided by (used in) operating activities			1,154	(6,136)
INVESTING ACTIVITIES
Capital expenditures			(1,826)	(1,777)
Net cash used in investing activities			(1,826)	(1,777)
FINANCING ACTIVITIES
Proceeds from issuance of debt			0	3,678
Payments on debt			(723)	(1,120)
Net activity on related-party debt			924	968
Net cash provided by financing activities			201	3,526
Net change in cash, cash equivalents, and restricted cash			(471)	(4,387)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD			2,146	6,083	6,083
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$ 1,675	$ 1,696	1,675	1,696	$ 2,146
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable and capital leases			82	1,651
Financing of guaranty fees via long-term debt, related party			485	171
Conversion of accounts payable to short-term notes			0	0
Conversion of related-party notes to common stock			0	831
Interest paid			2,173	1,574
Income taxes paid			$ 0	$ 0

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1. Organization

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Nature of Operations. Blue Dolphin Energy Company is a publicly-traded Delaware corporation primarily engaged in the refining and marketing of petroleum products. We also provide tolling and storage terminaling services. Our assets, which are located in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and approximately 1.1 million bbls of petroleum storage tanks (collectively the “Nixon Facility”). Pipeline transportation and oil and gas operations are no longer active.

Structure and Management. Blue Dolphin is controlled by Lazarus Energy Holdings, LLC (“LEH”). LEH operates and manages all Blue Dolphin properties pursuant to an Amended and Restated Operating Agreement (the “Amended and Restated Operating Agreement”). Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. Together LEH and Jonathan Carroll own 80.2% of our common stock, par value $0.01 per share (the “Common Stock”). (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Amended and Restated Operating Agreement, and Jonathan Carroll.)

We have the following active subsidiaries:

● Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”);

● Blue Dolphin Petroleum Company, a Delaware corporation;

● Blue Dolphin Services Co., a Texas corporation (“BDSC”);

● Lazarus Energy, LLC, a Delaware limited liability company (“LE”);

● Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”); and

● Nixon Product Storage, LLC, a Delaware limited liability company (“NPS”);

In June 2018, Blue Dolphin acquired 100% of the issued and outstanding membership interests of NPS from Lazarus Midstream Partners, L.P., an affiliate of LEH, pursuant to an Assignment Agreement. The assignment was accounted for as a combination of entities under common control. See “Note (5) NPS Assignment” of this Quarterly Report for further information related to the NPS assignment.

See “Part I, Item 1. Business” and “Item 2. Properties” in the Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets.

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:

● Final Arbitration Award and Settlement Agreement – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of approximately $31.3 million. As of the date of this report, LE has paid $9.2 million to GEL towards reducing the outstanding balance of the Final Arbitration Award. After the $3.7 million initial payment to GEL in September 2017, LE has made payments to GEL at $0.5 million per month.

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

On July 20, 2018, LE, NPS, and Blue Dolphin, together with LEH, Carroll & Company Financial Holdings, L.P. (“C&C”), and Jonathan Carroll (collectively referred to herein as the “Lazarus Parties”), entered into a Settlement Agreement with GEL (the “Settlement Agreement”), 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 the GEL Arbitration (the “Settlement”), subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon payment by the Lazarus Parties to GEL of $10.0 million in cash (the “Settlement Payment”) and $0.5 million in cash at the end of each calendar month until the Settlement Payment is paid (the “Interim Payments”) or the Settlement Agreement is terminated. The Interim Payments will not be applied to reduce the amount of the Settlement Payment, but such payments will reduce the Final Arbitration Award. At September 30, 2018 and December 31, 2017, accrued arbitration award payable on our consolidated balance sheet was $23.1 million and $27.1 million, respectively. At the time of the Settlement, the difference between the Settlement Payment and the amount we have accrued on our consolidated balance sheet for arbitration award payable will be recognized as a gain on our consolidated statement of operations.

The Settlement Agreement restricts the Lazarus Parties from taking certain actions without the prior written consent of GEL, including: (i) the incurrence of any debt not specifically excepted in the Settlement Agreement, (ii) the establishment of any liens not specifically excepted in the Settlement Agreement, (iii) the disposition of any assets other than certain ordinary course sales to unaffiliated third parties, payments to unaffiliated third-party trade creditors and scheduled debt payments, (iv) the entrance into any transactions with affiliates not specifically excepted in the Settlement Agreement, (v) the failure to pay debts generally as they become due, and (vi) the entrance into a bankruptcy, reorganization or similar proceeding. A violation of any of the restrictions in the Settlement Agreement, as well as the failure of the Lazarus Parties to make Interim Payments as they become due, will constitute an event of default under the Settlement Agreement which, subject to certain cure periods, would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award.

The Lazarus Parties are exploring the possibility of obtaining a commercial loan or other financing in an aggregate principal amount equal to the Settlement Payment (the “Settlement Financing”), subject to obtaining the consent of Veritex Community Bank (“Veritex”), as lender under certain loan agreements with the Lazarus Parties and their affiliates. Under the Settlement Agreement, the Lazarus Parties are required to work in good faith and take reasonable actions necessary to obtain the Settlement Financing in accordance with the terms of the Settlement Agreement. Prior to the consummation of the Settlement Financing, the Lazarus Parties are required to: (i) cause NPS to consummate the Settlement Financing and restrict its ability to commence a bankruptcy case, (ii) assign to NPS certain tank leases that will constitute collateral for the Settlement Financing, and (iii) cause NPS to assume joint and several liability for all or a portion of the Final Arbitration Award. The failure to achieve certain milestones in connection with obtaining the Settlement Financing will constitute an event of default under the Settlement Agreement, which would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award.

Simultaneously with the execution of the Settlement Agreement, Jonathan Carroll and C&C entered into a Security Agreement pursuant to which Jonathan Carroll and C&C agreed to secure up to $10.0 million of LE’s obligations under the Final Arbitration Award with a security interest in their equity in LEH.

The Settlement Agreement will terminate, unless extended in writing by GEL, on December 31, 2018 if the Settlement Payment is not made on or before such date, and the Settlement Agreement may be terminated by GEL following the occurrence of an event of default under the Settlement Agreement, as described above. Pursuant to the Settlement Agreement, the parties agreed to terminate the Letter Agreement, and GEL agreed not to take any action to execute or collect on the Final Arbitration Award and to take all action necessary to continue the District Court Action until the earlier of: (i) the date on which the Settlement Payment is paid or (ii) the termination of the Settlement Agreement.

Blue Dolphin can provide no assurance that the conditions necessary for consummation of the Settlement will be met. If certain conditions are not met or the Settlement Agreement is terminated, GEL may seek to enforce the Final Arbitration Award against the Lazarus Parties, in which case: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

● Veritex Secured Loan Agreement Event of Default – Veritex, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the Settlement Agreement. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Additionally, Veritex must ultimately approve the Settlement. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future.

We can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement Agreement, any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations, and Blue Dolphin would likely be required to seek protection under bankruptcy laws.

Operating Risks. Successful execution of our business plan depends on several key factors, including the Settlement with GEL, having adequate crude oil and condensate supplies, maintaining safe and reliable operations at the Nixon Facility, having favorable margins on refined petroleum products, and meeting contractual obligations. (See “Part I, Item 1. Business – Business Strategies” in the Annual Report for information related to our business plan.)

For the three months ended September 30, 2018, we reported a net loss of $0.9 million, or a loss of $0.09 per share, compared to net income of $3.9 million, or income of $0.36 per share, for the three months ended September 30, 2017. Net loss for the three months ended September 30, 2018 was primarily the result of lower and sometimes negative margins on refined petroleum products, while net income for the three months ended September 30, 2017 was primarily the result of favorable margins for refined petroleum products.  

For the nine months ended September 30, 2018, we reported net income of $0.7 million, or income of $0.07 per share, compared to a net loss of $23.3 million, or a loss of $2.19 per share, for the nine months ended September 30, 2017. The nine months ended September 30, 2017 included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million in arbitration award and associated fees and represented an expense of $2.29 per share. Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.26 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis declined $0.03 between the periods, which was primarily the result of slightly lower margins for refined petroleum products.

Execution of our business plan was hindered during the three months ended September 30, 2018 by several factors, including:

● Working Capital Deficits – We had a working capital deficit of $71.0 million at September 30, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $29.5 million at September 30, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017.

● Crude Supply – Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, and other factors, as noted above.

● Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018 LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would 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 sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to the Settlement Agreement with GEL, or provide future waivers of any financial covenant defaults, which would have an adverse impact on our financial position and results of operations.

We are continuing aggressive actions to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability. However, there can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. If Veritex does not approve the Settlement or if the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws.

For additional disclosures related to the Final Arbitration Award, the GEL Letter Agreement, the Settlement Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Quarterly Report:

● Part I, Item 1. Financial Statements, Notes to Consolidated Financial Statements:

Note (9) Related Party Transactions

Note (11) Long-Term Debt, Net

Note (18) Commitments and Contingencies – Legal Matters

● Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations:

Final Arbitration Award

Results of Operations

Liquidity and Capital Resources

● Part II, Item 1. Legal Proceedings

● Part II, Item 1A. Risk Factors

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2. Basis of Presentation

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Articles 8 and 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. 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.

The consolidated balance sheet as of December 31, 2017 was derived from the audited financial statements at that date.  The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report.  Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2018, or for any other period.

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3. Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.

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 GAAP. We believe our current estimates are reasonable and appropriate; however, actual results could differ from those estimated.

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: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks.

Inventory. Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of sales. (See “Note (7) Inventory” for additional disclosures related to our inventory.)

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance on accounting for the impairment or disposal of long-lived assets, management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, our pipeline assets were fully impaired. All pipeline transportation services to third parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines.

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

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

(See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name. We account for intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we determined trade name to have an indefinite useful life, and we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2017. Upon completion of that testing, our trade name asset was fully impaired at December 31, 2017.

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability. (See “Note (11) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

Revenue Recognition.

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

Refinery Operations Revenue. Revenue from the sale of refined petroleum products is recognized when the product is sold to a customer in fulfillment of performance obligations. Each barrel of refined petroleum product, or other unit of measure, 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 in accordance with the terms of the respective sales agreement. We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant. Transportation, shipping, and handling costs incurred are included in cost of sales. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

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

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines 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 the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our 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 September 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”).

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 September 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.)

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the 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. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented.

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

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and 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. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (12) Asset Retirement Obligations” for additional information related to our AROs.)

Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which 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. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. 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 options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.)

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include:

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

New Pronouncements Issued, Not Yet Effective. The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows:

ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In July 2018, FASB issued ASUs 2018-11 and 2018-10. ASU 2018-11 provides entities with relief from the costs of implementing certain aspects of ASU 2016-02 (codified as ASC 842). Specifically, under the amendments in ASU 2018-11: (i) Entities may elect not to recast the comparative periods presented when transitioning to ASC 842 (Issue 1), and (ii) Lessors may elect not to separate lease and non-lease components when certain conditions are met (Issue 2). ASU 2018-10 made 16 separate amendments to ASC 842. For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in: (i) the recognition of a liability to make lease payments and a right-to-use asset representing our right to use the underlying asset on our consolidated balance sheets and (ii) the recognition of an expense on our consolidated statements of operations each month as we amortize the right-to-use asset.

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

ASU 2018-07, Compensation – Stock Compensation (Topic 718). In June 2018, FASB issued ASU 2018-07. This guidance expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The amendments in ASU 2018-07 are effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

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

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4. Business Segment Information

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Business 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 related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility.

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

	Three Months Ended September 30,
	2018												2017
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Corporate
	Operations			Terminaling			& Other			Total			Operations			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	94,468		$	1,075		$	-		$	95,543		$	66,899		$	-		$	66,899
Intercompany fees and sales		(873	)		873			-			-			-			-			-
Operation costs and expenses(1)
Cost of materials and other		(92,571	)		-			-			(92,571	)		(58,786	)		-			(58,786	)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)		(1,085	)		(624	)		(94	)		(1,803	)		(1,758	)		(140	)		(1,898	)
Segment contribution margin	$	(61	)	$	1,324		$	(94	)	$	1,169		$	6,355		$	(140	)	$	6,215
General and administrative expenses		(375	)		(65	)		(489	)		(929	)		(913	)		(327	)		(1,240	)
Depreciation and amortization		(432	)		(46	)		-			(478	)		(452	)		(3	)		(455	)
Interest and other non-operating expenses, net											(742	)								(574	)
Income (loss) before income taxes											(980	)								3,946
Income tax benefit											43									-
Net income (loss)										$	(937	)							$	3,946
Capital expenditures	$	372		$	223		$	-		$	595		$	539		$	-		$	539
Identifiable assets	$	51,816		$	19,425		$	926		$	72,167		$	70,792		$	2,068		$	72,860

(1)  Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

	Nine Months Ended September 30,
	2018												2017
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Corporate
	Operations			Terminaling			& Other			Total			Operations			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	254,245		$	2,659		$	-		$	256,904		$	176,842		$	-		$	176,842
Intercompany fees and sales		(2,419	)		2,419			-			-			-			-			-
Operation costs and expenses(1)
Cost of materials and other		(244,380	)		-			-			(244,380	)		(189,525	)		-			(189,525	)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)		(3,698	)		(2,092	)		(338	)		(6,128	)		(6,223	)		(399	)		(6,622	)
Segment contribution margin	$	3,748		$	2,986		$	(338	)	$	6,396		$	(18,906	)	$	(399	)	$	(19,305	)
General and administrative expenses		(929	)		(156	)		(1,192	)		(2,277	)		(1,960	)		(894	)		(2,854	)
Depreciation and amortization		(1,258	)		(138	)		-			(1,396	)		(1,348	)		(8	)		(1,356	)
Interest and other non-operating income (expenses)(2)											(2,235	)								217
Income (loss) before income taxes											488									(23,298	)
Income tax benefit											260									-
Net income (loss)										$	748								$	(23,298	)
Capital expenditures	$	1,141		$	767		$	-		$	1,908		$	3,428		$	-		$	3,428
Identifiable assets	$	51,816		$	19,425		$	926		$	72,167		$	70,792		$	2,068		$	72,860

(1)

Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

(2)

Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

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5. NPS Assignment

9 Months Ended

Sep. 30, 2018

Nps Assignment

NPS Assignment

In June 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS, a Delaware limited liability company, from Lazarus Midstream Partners, L.P. (“Lazarus Midstream”), an affiliate of LEH, pursuant to an Assignment Agreement. The transaction represents transfer of a vacant shell entity owned by Lazarus Midstream to Blue Dolphin for the nominal fee of $10.00. The assignment of interest facilitates the Lazarus Parties exploring the possibility of obtaining the Settlement Financing under the 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 the three and nine months ended September 30, 2018. NPS did not have significant assets, liabilities or results of operations for the three and nine months ended September 30, 2017. 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.

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6. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 2018

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid Expenses and Other Current Assets

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

	September 30,		December 31,
	2018		2017
	(in thousands)
Prepaid insurance	$	408	$	294
Other prepaids		39		-
Prepaid crude oil and condensate		-		913
	$	447	$	1,207

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7. Inventory

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,		December 31,
	2018		2017
	(in thousands)
Crude oil and condensate	$	1,571	$	961
AGO		449		213
HOBM		256		1,558
Naphtha		234		170
Chemicals		94		162
Propane		18		17
LPG mix		5		8
	$	2,627	$	3,089

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8. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

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

	September 30,			December 31,
	2018			2017
	(in thousands)
Refinery and facilities	$	54,210		$	51,432
Land		566			566
Other property and equipment		747			653
		55,523			52,651
Less: Accumulated depletion, depreciation, and amortization		(9,892	)		(8,495	)
		45,631			44,156
Construction in progress		19,478			20,441
	$	65,109		$	64,597

We capitalize interest cost incurred on funds used to construct property, plant, and equipment. Capitalized interest, which is recorded as part of the asset to which it relates, is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $4.2 million and $3.9 million at September 30, 2018 and December 31, 2017, respectively. We expect construction of petroleum storage tanks at the Nixon Facility to continue until year end.

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9. Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

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

Related Parties.

LEH. LEH is our controlling shareholder. Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. Together, LEH and Jonathan Carroll own 80.2% of our Common Stock. Related party agreements with LEH include: (i) an Amended and Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL, (iv) an Amended and Restated Promissory Note with Blue Dolphin, and (v) a Debt Assumption Agreement with LE. Additionally, in June 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS from Lazarus Midstream pursuant to an Assignment Agreement. (See “Note (5) NPS Assignment” for further discussion related to the NPS transaction.)

Ingleside Crude, LLC (“Ingleside”). Ingleside is a related party of LEH and Jonathan Carroll. Blue Dolphin is party to an Amended and Restated Promissory Note with Ingleside.

Lazarus Marine Terminal I, LLC (“LMT”). LMT is a related party of LEH and Jonathan Carroll. LE is party to a Dock Tolling Agreement with LMT.

Jonathan Carroll. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin. Related party agreements with Jonathan Carroll include: (i) Amended and Restated Guaranty Fee Agreements with LE and LRM and (ii) an Amended and Restated Promissory Note with Blue Dolphin.

Currently, we depend on LEH and its affiliates (including Jonathan Carroll and Ingleside) for financing when revenue from operations and borrowings under bank facilities are insufficient to meet our liquidity needs. Such borrowings are reflected in our consolidated balance sheets in accounts payable, related party, and/or long-term debt, related party.

Operations Related Agreements.

Amended and Restated Operating Agreement. LEH operates and manages all Blue Dolphin properties pursuant to the Amended and Restated Operating Agreement. The Amended and Restated Operating Agreement, which was restructured in 2017 following cessation of crude supply and marketing activities under the Crude Supply Agreement and Joint Marketing Agreement with GEL, expires: (i) April 1, 2020, (ii) upon written notice by either party to the Amended and Restated Operating Agreement of a material breach by the other party, or (iii) upon 90 days’ notice by the Board if the Board determines that the Amended and Restated Operating Agreement is not in our best interest. LEH receives an operating fee of 5% of Blue Dolphin’s direct operating expenses. LEH’s operating fee and Blue Dolphin’s direct operating expenses are reflected within refinery operating expenses in our consolidated statements of operations.

Jet Fuel Sales Agreement. LE sells jet fuel to LEH pursuant to a Jet Fuel Sales Agreement. LEH resells the jet fuel purchased from LE to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. The Jet Fuel Sales Agreement terminates on the earliest to occur of: (a) a one-year term expiring March 31, 2019 plus a 30-day carryover or (b) delivery of a maximum quantity of jet fuel as defined therein. Sales to LEH under the Jet Fuel Sales Agreement are reflected within refinery operations revenue in our consolidated statements of operations. (LRM previously leased petroleum storage tanks to LEH for the storage of the jet fuel under a Terminal Services Agreement. The Terminal Services Agreement was terminated as described below).

Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leased petroleum storage tanks from LRM for the storage of LEH purchased jet fuel under the Jet Fuel Sales Agreement (as described above). The Terminal Services Agreement was terminated in June 2017. Rental fees received from LEH under the Terminal Services Agreement are reflected within tolling and terminaling revenue in our consolidated statements of operations.

Amended and Restated Tank Lease Agreement. Pursuant to an Amended and Restated Tank Lease Agreement with Ingleside, LE leased petroleum storage tanks to meet periodic, additional storage needs. The Amended and Restated Tank Lease Agreement was terminated in July 2017. Rental fees owed to Ingleside under the tank lease agreement are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets. Amounts expensed as rental fees to Ingleside under the Amended and Restated Tank Lease Agreement are reflected within refinery operating expenses in our consolidated statements of operations.

Dock Tolling Agreement. In May 2016, LE entered a Dock Tolling Agreement with LMT to facilitate loading and unloading of petroleum products by barge at LMT’s dock facility in Ingleside, Texas. The Dock Tolling Agreement has a five-year term and may be terminated at any time by the agreement of both parties. LE pays LMT a flat reservation fee monthly. The reservation fee includes tolling volumes up to 84,000 gallons per day. Excess tolling volumes are subject to an increased per gallon rate. Amounts expensed as tolling fees under the Dock Tolling Agreement are reflected in the cost of sales in our consolidated statements of operations.

Financial Agreements.

BDPL Loan Agreement (In Default). In August 2016, BDPL entered a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “BDPL Loan Agreement”). The BDPL Loan Agreement matured on August 15, 2018. Interest is still accruing at a rate of 16.00%. The BDPL Loan Agreement is currently in default due to non-payment.

The proceeds of the BDPL Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the BDPL Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the BDPL Loan Agreement is reflected in interest payable, related party, current portion in our consolidated balance sheets.

Promissory Notes. We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. During 2017, LEH and its affiliates (Ingleside and Jonathan Carroll) provided working capital to Blue Dolphin in the form of non-cash advances, such as conversions of accounts payable to debt. These non-cash advances are reflected in the below promissory notes. There can be no assurance that LEH and its affiliates will continue to fund our working capital requirements. Outstanding principal and accrued interest owed under these promissory notes are reflected in long-term debt, related party, current portion in our consolidated balance sheets.

● June LEH Note – In March 2017, Blue Dolphin entered a promissory note with LEH (the “March LEH Note”). In June 2017, the March LEH Note was amended and restated to increase the principal amount (the “June LEH Note”). The June LEH Note accrues interest at a rate of 8.00% and has a maturity date of January 2019. Interest under the June LEH Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

● March Ingleside Note – In March 2017, a promissory note between Blue Dolphin and Ingleside was amended and restated (the “March Ingleside Note”) to increase the principal and extend the maturity date to January 2019. Interest under the March Ingleside Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

● March Carroll Note – In March 2017, a promissory note between Blue Dolphin and Jonathan Carroll was amended and restated (the “March Carroll Note”) to increase the principal amount, revise the payment terms to reflect payment in cash and shares of Blue Dolphin Common Stock, and extend the maturity date to January 2019. Interest under the March Carroll Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3.6 million to GEL relating to the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3.7 million of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John Kissick. Debt held by John Kissick, including the debt associated with the Debt Assumption Agreement, is reported in this Quarterly Report as the Notre Dame Debt (defined below) and is reflected in long-term debt less unamortized debt issue costs, current portion in our consolidated balance sheets, as it is currently in default. (See “Note (11) Long-Term Debt, Net” for further discussion related to the Notre Dame Debt.)

Amended and Restated Guaranty Fee Agreements. Pursuant to Amended and Restated Guaranty Fee Agreements, Jonathan Carroll earns fees for providing his personal guarantee on certain LE and LRM long-term debt. Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain LE and LRM loan agreements. Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets. Amounts expensed related to Amended and Restated Guarantee Fee Agreements are reflected within interest and other expense in our consolidated statements of operations.

Financial Statements Impact.

Consolidated Balance Sheets. Accounts receivable, related party from LEH associated with the Jet Fuel Sales Agreement were $0 and $0.7 million at September 30, 2018 and December 31, 2017, respectively. Accounts payable, related party to LMT associated with the Dock Tolling Agreement were $1.4 million and $1.0 million at September 30, 2018 and December 31, 2017, respectively.

Long-term debt, related party associated with the BDPL Loan Agreement, March Ingleside Note, and the March Carroll Note as of the dates indicated was as follows:

	September 30,			December 31,
	2018			2017
	(in thousands)
LEH	$	4,303		$	4,000
Ingleside		1,263			1,169
Jonathan Carroll		966			439
		6,532			5,608
Less: Long-term debt, related party,
current portion		(6,532	)		(4,000	)
	$	-		$	1,608

Accrued interest associated with the BDPL Loan Agreement was $1.4 million and $0.9 million at September 30, 2018 and December 31, 2017, respectively.

Consolidated Statements of Operations. Revenue from related parties was as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands, except percent amounts)
Refinery operations
LEH	$	27,299	28.7	%	$	20,803	31.1	%	$	73,415	28.6	%	$	59,786	33.8	%
Other customers		67,169	70.4	%		45,330	67.8	%		180,830	70.4	%		114,882	65.0	%
Tolling and terminaling
LEH		-	0.0	%		56	0.1	%		-	0.0	%		675	0.4	%
Other customers		1,075	0.9	%		710	1.0	%		2,659	1.0	%		1,499	0.8	%
	$	95,543	100.0	%	$	66,899	100.0	%	$	256,904	100.0	%	$	176,842	100.0	%

Fees associated with the Dock Tolling Agreement with LMT totaled $0.2 million for both the three months ended September 30, 2018 and 2017. Fees associated with the Dock Tolling Agreement with LMT totaled $0.6 million for both the nine months ended September 30, 2018 and 2017.

Expenses and fees associated with the Amended and Restated Operating Agreement with LEH for the periods indicated were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	Amount		per bbl		Amount		per bbl		Amount		per bbl		Amount		per bbl
	(in thousands, except per bbl amounts)
Blue Dolphin's direct operating expenses	$	1,033		0.85	$	1,674		1.46	$	4,175		1.22	$	5,927		1.84
LEH operating fee		52		0.04		84		0.07		209		0.06		296		0.09
Total refinery operating expenses	$	1,085	$	0.89	$	1,758	$	1.53	$	4,384	$	1.28	$	6,223	$	1.93

For the three months ended September 30, 2018, refinery operating expenses decreased approximately $0.7 million, or $0.64 per bbl, compared to the same period a year earlier. For the nine months ended September 30, 2018, refinery operating expenses decreased approximately $1.8 million, or $0.65 per bbl, compared to the same nine-month period a year earlier. The decrease in refinery operating expenses was due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement, as well as management’s efforts to reduce spending.

Interest expense associated with the BDPL Loan Agreement, the Restated Guaranty Fee Agreements, and the related-party promissory notes (the June LEH Note, the March Ingleside Note, and March Carroll Note) for the periods indicated was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Jonathan Carroll	$	180	$	171	$	519	$	521
LEH		166		164		489		542
Ingleside		25		23		96		69
	$	371	$	358	$	1,104	$	1,132

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10. Accrued Expenses and Other Current Liabilities

9 Months Ended

Sep. 30, 2018

Disclosure Text Block Supplement [Abstract]

Accrued Expenses and Other Current Liabilities

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

	September 30,		December 31,
	2018		2017
	(in thousands)
Board of director fees payable	$	270	$	207
Other payable		205		116
Unearned revenue		125		450
Property taxes		122		131
Customer deposits		109		109
Excise and income taxes payable		32		79
Insurance		-		68
	$	863	$	1,160

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11. Long-Term Debt, Net

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt, Net

Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
First Term Loan Due 2034 (in default)	$	22,663		$	23,199
Second Term Loan Due 2034 (in default)		9,344			9,502
Notre Dame Debt (in default)		4,978			4,978
Capital leases		51			-
	$	37,036		$	37,679
Less: Current portion of long-term debt, net		(34,988	)		(35,544	)
Less: Unamortized debt issue costs		(2,038	)		(2,135	)
	$	10		$	-

Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
First Term Loan Due 2034 (in default)	$	1,674		$	1,674
Second Term Loan Due 2034 (in default)		768			768
Less: Accumulated amortization		(404	)		(307	)
	$	2,038		$	2,135

Amortization expense was $0.03 million for both the three months ended September 30, 2018 and 2017. Amortization expense was $0.1 million for both the nine months ended September 30, 2018 and 2017.

Accrued interest associated with long-term debt, net is reflected as interest payable, in default and interest payable, related party, in default in our consolidated balance sheets. Accrued interest as of the dates indicated consisted of the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
Notre Dame Debt (in default)	$	2,643		$	2,046
BDPL Loan Agreement (related party, in default)		1,374			892
Second Term Loan Due 2034 (in default)		52			49
First Term Loan Due 2034 (in default)		39			40
		4,108			3,027
Less: Interest payable, current portion		(4,108	)		(3,027	)
Long-term interest payable, net of current portion	$	-		$	-

Related Party. See “Note (9) Related Party Transactions” for additional disclosures with respect to related party long-term debt.

First Term Loan Due 2034 (In Default). LE has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender. The loan agreement is for a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”). The First Term Loan Due 2034 matures in June 2034, has a current monthly payment of principal and interest of $0.2 million, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use 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 Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LE was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LE entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the First Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the First Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the First Term Loan Due 2034 totaled $0.1 million for both the three months ended September 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the First Term Loan Due 2034 totaled $0.3 million and $0.4 million for the nine months ended September 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a payment reserve account held by Veritex, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type.

Second Term Loan Due 2034 (In Default). LRM has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender. The loan agreement is for a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”). The Second Term Loan Due 2034 matures in December 2034, has a current monthly payment of principal and interest of $0.1 million, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use 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 Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LRM was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the Second Term Loan Due 2034. The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the Second Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.05 million and $0.05 million for the three months ended September 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.1 million and $0.1 million for the nine months ended September 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million, the funds of which were used to purchase idle refinery equipment for refurbishment and use at the Nixon Facility. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type.

Notre Dame Debt (In Default). LE entered a loan with Notre Dame Investors, Inc. as evidenced by a promissory note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). Pursuant to a Sixth Amendment to the Notre Dame Debt, entered on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended to increase the principal amount by $3.7 million (the “Additional Principal”). The Additional Principal was used to make payments to GEL to reduce the balance of the Final Arbitration Award in the amount of $3.6 million in accordance with the GEL Letter Agreement. Interest on the principal accrues at a rate of 16.00%. The Notre Dame Debt matured in January 2018, however, pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate its right to payments, as well as any security interest and liens on the Nixon Facility, in favor of Veritex as holder of the First Term Loan Due 2034.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt.

Capital Leases.

Boiler Equipment Lease. In 2014, LRM entered a 36-month build-to-suit capital lease for the purchase two new boilers for the Nixon Facility. One of the boilers was placed in service during the second quarter of 2017. The other boiler remains in construction in progress. The lease was paid off during the three months ended March 31, 2018.

Crane Lease. In January 2018, LE entered a 24-month capital lease for the purchase of a 20-ton crane for use at the Nixon Facility. The lease requires a negligible monthly payment and matures in January 2020.

A summary of equipment held under long-term capital leases as of the dates indicated follows:

	September 30,			December 31,
	2018			2017
	(in thousands)
Crane	$	94		$	-
Less: accumulated depreciation		(10	)		-
	$	84		$	-

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12. Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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. We depreciate the amount added to property and equipment and recognize accretion expense relating to the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

Changes to our ARO liability for the periods indicated were as follows:

	September 30,			December 31,
	2018			2017
	(in thousands)
Asset retirement obligations, at the beginning of the period	$	2,315		$	2,028
Liabilities settled		(1	)		-
Accretion expense		205			287
		2,519			2,315
Less: asset retirement obligations, current portion		(2,519	)		(2,315	)
Long-term asset retirement obligations, at the end of the period	$	-		$	-

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13. Treasury Stock

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Treasury Stock

At September 30, 2018 and December 31, 2017, we had 0 shares of treasury stock. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

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14. Concentration of Risk

9 Months Ended

Sep. 30, 2018

Risks and Uncertainties [Abstract]

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 our cash balances at financial institutions located in Houston, Texas. In the U.S., the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. At September 30, 2018 and December 31, 2017, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $1.2 million and $1.6 million, respectively.

Key Supplier.

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

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

For the three months ended September 30, 2018, we had 4 customers that accounted for approximately 94% of refinery operations revenue. LEH, a related party, was 1 of these 4 significant customers and accounted for approximately 29% of refinery operations revenue. At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable. LEH represented approximately $0 in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

For the three months ended September 30, 2017, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 32% of our refined petroleum product sales.  At September 30, 2017, these 4 customers represented approximately $1.5 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

For the nine months ended September 30, 2018, we had 4 customers that accounted for approximately 90% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 29% of our refined petroleum product sales.  At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable.  LEH represented approximately $0 in accounts receivable.

For the nine months ended September 30, 2017, we had 3 customers that accounted for approximately 67% of our refined petroleum product sales.  LEH was 1 of these 3 significant customers and accounted for approximately 34% of our refined petroleum product sales.  At September 30, 2017, these 3 customers represented approximately $1.2 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

Refined Petroleum Product Sales. Our refined petroleum products are primarily sold in the U.S. However, with the opening of the Mexican diesel market to private companies, we occasionally sell low-sulfur diesel to customers that export to Mexico. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)
LPG mix	$	-	0.0	%	$	-	0.0	%	$	3	0.0	%	$	121	0.1	%
Naphtha		24,127	25.5	%		14,266	21.6	%		64,093	25.2	%		41,283	24.9	%
Jet fuel		27,299	28.9	%		20,803	31.5	%		73,415	28.9	%		56,361	32.8	%
HOBM		21,735	23.0	%		17,011	25.7	%		60,594	23.8	%		38,580	19.9	%
AGO		21,307	22.6	%		14,053	21.2	%		56,140	22.1	%		38,323	22.3	%
	$	94,468	100.0	%	$	66,133	100.0	%	$	254,245	100.0	%	$	174,668	100.0	%

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15. Leases

9 Months Ended

Sep. 30, 2018

Leases, Operating [Abstract]

Leases

BDSC leases our principal office space in Houston, Texas under a 2006 lease agreement. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that extended the lease period by sixty-eight (68) months expiring on August 31, 2023. Under the Lease Amendment, our base rent for 6,489 square feet is $0.01 million per month. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For both the three months ended September 30, 2018 and 2017, rent expense totaled $0.03 million. For both the nine months ended September 30, 2018 and 2017, rent expense totaled $0.1 million.

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16. Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The principal element of the Tax Cuts and Jobs Act relevant to our financial statements is a reduction in the U.S. federal corporate tax rate from 34% to 21%, effective January 1, 2018. Other provisions of the Tax Cuts and Jobs Act did not have a significant impact on our financial statements for the three and nine months ended September 30, 2018.

For the three months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.04 million and $0, respectively. For the nine months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.2 million and $0, respectively.

The provision for income tax benefit (expense) as of the dates indicated consisted of the following:

	September 30,		December 31,
	2018		2017
	(in thousands)
Current
Federal	$	108	$	-
State		43		-
Deferred
Impact of change in enacted tax rates		-		(6,654	)
Change in valuation allowance		109		6,654
Total provision for income taxes	$	260	$	-

In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to Alternative Minimum Tax credits made refundable by the Tax Cuts and Jobs Act. In 2017, our effective tax rate differed from the U.S. federal statutory rate primarily due to re-measuring deferred income taxes at the new statutory tax rate and the related change of the valuation allowance over our deferred tax assets. 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. This had no impact on our net deferred tax assets.

The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross profit rather than on its net income, certain aspects of TMT make it like an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. For the three and nine months ended September 30, 2018 and 2017, we recognized income relating to state income tax of $0.04 million and $0, respectively.

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

	September 30,			December 31,
	2018			2017
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	11,814		$	9,767
Accrued arbitration award payable		3,048			4,122
Start-up costs (crude oil and condensate processing facility)		699			763
Asset retirement obligations liability/deferred revenue		6			495
AMT credit and other		15			217
Total deferred tax assets		14,033			15,365
Deferred tax liabilities:
Basis differences in property and equipment		(4,936	)		(4,415	)
Total deferred tax liabilities		(4,936	)		(4,415	)
		9,097			10,950
Valuation allowance		(10,538	)		(10,950	)
Deferred tax assets, net	$	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 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 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 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, 2016	$	9,614	$	23,562	$	33,176
Net operating losses		-		6,656		6,656
Balance at December 31, 2017	$	9,614	$	30,218	$	39,832
Net operating losses		-		9,747		9,747
Balance at September 30, 2018	$	9,614	$	39,965	$	49,579

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 September 30, 2018 and December 31, 2017, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2018 and December 31, 2017.

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17. Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018		2017
	(in thousands, except share and
	per share amounts)
Net income (loss)	$	(937	)	$	3,946	$	748	$	(23,298	)
Basic and diluted income (loss) per share	$	(0.09	)	$	0.36	$	0.07	$	(2.19	)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,925,513			10,818,371		10,925,513		10,644,654

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 the three and nine months ended September 30, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

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18. Commitments and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Legal Matters.

Final Arbitration Award and Settlement Agreement. See “Note (1) Organization – Going Concern – Final Arbitration Award and Settlement Agreement” and "Part II, Item 1. Legal Proceedings” for additional disclosures related to the Final Arbitration Award and the Settlement Agreement.

Veritex Secured Loan Agreement Event of Default. See “Note (1) Organization – Going Concern – Veritex Secured Loan Agreement Event of Default” and “Note (11) Long-Term Debt, Net” for disclosures related to defaults under secured loan agreements.

Other Legal Matters. From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

Amended and Restated Operating Agreement. See “Note (9) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.

FLNG Easements. BDPL and FLNG were parties to a Pipeline Easement dated November 5, 2005 (the “FLNG Pipeline Easement”) and the FLNG Master Easement Agreement (together with the FLNG Pipeline Easement, the “FLNG Easements”). The FLNG Easements provided FLNG and its affiliates: (i) a pipeline easement and right of way across BDPL-owned property to certain property owned by FLNG and (ii) rights of ingress and egress across BDPL-owned property to the property owned by FLNG. Under the FLNG Easements, FLNG made payments to us in the amount of $0.5 million each year. The FLNG Easements were terminated in February 2017.

Financing Agreements. See “Note (11) Long-Term Debt, Net” for additional disclosures related to financing agreements.

Guarantees. LEH and Jonathan Carroll have provided guarantees on certain Blue Dolphin-related long-term debt. The maximum amount of any guarantee is reduced as payments are made. See “Note (11) Long-Term Debt, Net” for additional disclosures related to guarantees.

Health, Safety and Environmental Matters. All our operations and properties 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 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 greenhouse gas 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. We have made and 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 and completion of petroleum storage tanks.

Supplemental Pipeline Bonds. In a letter dated March 30, 2018, the Bureau of Ocean Energy Management (the “BOEM”) ordered BDPL to provide additional supplemental bonds or acceptable financial assurance of approximately $4.8 million (the “Separate Orders”) within sixty (60) calendar days of receipt of the letter. The Separate Orders relate to five (5) existing pipeline rights-of-way. BOEM issued an Incident of Noncompliance (“INC”) for each Separate Order dated June 8, 2018 and received by BDPL on June 11, 2018. BOEM asserts that the INCs authorize BOEM to impose financial penalties on BDPL if it does not comply with the Separate Orders within twenty days. BOEM asserts that potential penalties accrue for each day BDPL failed to comply after June 28, 2018.  BDPL appealed the INCs on August 8, 2018 and its deadline for filing a Statement of Reasons with BOEM has been extended by the Interior Board of Land Appeals (the “IBLA”). BDPL’s appeal of the Separate Orders was denied by the IBLA on October 18, 2018. BDPL’s pending appeal of the INCs does not relieve BDPL of its obligations to provide additional financial assurance in accordance with the Separate Orders, or of BOEM’s authority to impose financial penalties.

BDPL has initiated settlement discussions with BOEM to resolve the Separate Orders and the INCs. There can be no assurance that BOEM will: (i) accept a proposal for a reduced amount of supplemental financial assurance, (ii) not require additional supplemental pipeline bonds related to BDPL’s existing pipeline rights-of-way, and/or (iii) not impose penalties under the INCs. As a result, we are unable to predict the outcome of the discussions with BOEM or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded a liability on our consolidated balance sheet as of September 30, 2018. As of September 30, 2018 and December 31, 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition.

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3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Use of Estimates

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 GAAP. We believe our current estimates are reasonable and appropriate; however, actual results could differ from those estimated.

Cash and Cash Equivalents

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. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks.

Inventory

Inventory. Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of sales. (See “Note (7) Inventory” for additional disclosures related to our inventory.)

Property and Equipment

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance on accounting for the impairment or disposal of long-lived assets, management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, our pipeline assets were fully impaired. All pipeline transportation services to third parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines.

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

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

(See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles - Other

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name. We account for intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we determined trade name to have an indefinite useful life, and we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2017. Upon completion of that testing, our trade name asset was fully impaired at December 31, 2017.

Debt Issue Costs

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability. (See “Note (11) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

Revenue Recognition

Revenue Recognition.

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

Refinery Operations Revenue. Revenue from the sale of refined petroleum products is recognized when the product is sold to a customer in fulfillment of performance obligations. Each barrel of refined petroleum product, or other unit of measure, 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 in accordance with the terms of the respective sales agreement. We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between delivery and when payments are due is not significant. Transportation, shipping, and handling costs incurred are included in cost of sales. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

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

Income Taxes

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines 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 the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our 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 September 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”).

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 September 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.)

Impairment or Disposal of Long-Lived Assets

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the 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. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented.

Asset Retirement Obligations

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

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and 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. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (12) Asset Retirement Obligations” for additional information related to our AROs.)

Computation of Earnings Per Share

Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which 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. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. 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 options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.)

New Pronouncements Adopted

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include:

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

New Pronouncements Issued but Not Yet Effective

New Pronouncements Issued, Not Yet Effective. The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows:

ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In July 2018, FASB issued ASUs 2018-11 and 2018-10. ASU 2018-11 provides entities with relief from the costs of implementing certain aspects of ASU 2016-02 (codified as ASC 842). Specifically, under the amendments in ASU 2018-11: (i) Entities may elect not to recast the comparative periods presented when transitioning to ASC 842 (Issue 1), and (ii) Lessors may elect not to separate lease and non-lease components when certain conditions are met (Issue 2). ASU 2018-10 made 16 separate amendments to ASC 842. For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in: (i) the recognition of a liability to make lease payments and a right-to-use asset representing our right to use the underlying asset on our consolidated balance sheets and (ii) the recognition of an expense on our consolidated statements of operations each month as we amortize the right-to-use asset.

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

ASU 2018-07, Compensation – Stock Compensation (Topic 718). In June 2018, FASB issued ASU 2018-07. This guidance expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. The amendments in ASU 2018-07 are effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. Early adoption is permitted, but no earlier than an entity’s adoption date of Topic 606. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

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

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4. Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Business segment reporting

	Three Months Ended September 30,
	2018												2017
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Corporate
	Operations			Terminaling			& Other			Total			Operations			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	94,468		$	1,075		$	-		$	95,543		$	66,899		$	-		$	66,899
Intercompany fees and sales		(873	)		873			-			-			-			-			-
Operation costs and expenses(1)
Cost of materials and other		(92,571	)		-			-			(92,571	)		(58,786	)		-			(58,786	)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)		(1,085	)		(624	)		(94	)		(1,803	)		(1,758	)		(140	)		(1,898	)
Segment contribution margin	$	(61	)	$	1,324		$	(94	)	$	1,169		$	6,355		$	(140	)	$	6,215
General and administrative expenses		(375	)		(65	)		(489	)		(929	)		(913	)		(327	)		(1,240	)
Depreciation and amortization		(432	)		(46	)		-			(478	)		(452	)		(3	)		(455	)
Interest and other non-operating expenses, net											(742	)								(574	)
Income (loss) before income taxes											(980	)								3,946
Income tax benefit											43									-
Net income (loss)										$	(937	)							$	3,946
Capital expenditures	$	372		$	223		$	-		$	595		$	539		$	-		$	539
Identifiable assets	$	51,816		$	19,425		$	926		$	72,167		$	70,792		$	2,068		$	72,860

(1)  Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

	Nine Months Ended September 30,
	2018												2017
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Corporate
	Operations			Terminaling			& Other			Total			Operations			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	254,245		$	2,659		$	-		$	256,904		$	176,842		$	-		$	176,842
Intercompany fees and sales		(2,419	)		2,419			-			-			-			-			-
Operation costs and expenses(1)
Cost of materials and other		(244,380	)		-			-			(244,380	)		(189,525	)		-			(189,525	)
Operating expenses (excluding depreciation and amortization
and general and administrative expenses presented below)		(3,698	)		(2,092	)		(338	)		(6,128	)		(6,223	)		(399	)		(6,622	)
Segment contribution margin	$	3,748		$	2,986		$	(338	)	$	6,396		$	(18,906	)	$	(399	)	$	(19,305	)
General and administrative expenses		(929	)		(156	)		(1,192	)		(2,277	)		(1,960	)		(894	)		(2,854	)
Depreciation and amortization		(1,258	)		(138	)		-			(1,396	)		(1,348	)		(8	)		(1,356	)
Interest and other non-operating income (expenses)(2)											(2,235	)								217
Income (loss) before income taxes											488									(23,298	)
Income tax benefit											260									-
Net income (loss)										$	748								$	(23,298	)
Capital expenditures	$	1,141		$	767		$	-		$	1,908		$	3,428		$	-		$	3,428
Identifiable assets	$	51,816		$	19,425		$	926		$	72,167		$	70,792		$	2,068		$	72,860

(1)

Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

(2)

Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

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6. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2018

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid balances

	September 30,		December 31,
	2018		2017
	(in thousands)
Prepaid insurance	$	408	$	294
Other prepaids		39		-
Prepaid crude oil and condensate		-		913
	$	447	$	1,207

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7. Inventory (Tables)

9 Months Ended

Sep. 30, 2018

Inventory Disclosure [Abstract]

Inventory

	September 30,		December 31,
	2018		2017
	(in thousands)
Crude oil and condensate	$	1,571	$	961
AGO		449		213
HOBM		256		1,558
Naphtha		234		170
Chemicals		94		162
Propane		18		17
LPG mix		5		8
	$	2,627	$	3,089

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8. Property, Plant and Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property and equipment

	September 30,			December 31,
	2018			2017
	(in thousands)
Refinery and facilities	$	54,210		$	51,432
Land		566			566
Other property and equipment		747			653
		55,523			52,651
Less: Accumulated depletion, depreciation, and amortization		(9,892	)		(8,495	)
		45,631			44,156
Construction in progress		19,478			20,441
	$	65,109		$	64,597

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9. Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Accounts Payable, Related Party

	September 30,			December 31,
	2018			2017
	(in thousands)
LEH	$	4,303		$	4,000
Ingleside		1,263			1,169
Jonathan Carroll		966			439
		6,532			5,608
Less: Long-term debt, related party,
current portion		(6,532	)		(4,000	)
	$	-		$	1,608

Accrued interest Expenses

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands, except percent amounts)
Refinery operations
LEH	$	27,299	28.7	%	$	20,803	31.1	%	$	73,415	28.6	%	$	59,786	33.8	%
Other customers		67,169	70.4	%		45,330	67.8	%		180,830	70.4	%		114,882	65.0	%
Tolling and terminaling
LEH		-	0.0	%		56	0.1	%		-	0.0	%		675	0.4	%
Other customers		1,075	0.9	%		710	1.0	%		2,659	1.0	%		1,499	0.8	%
	$	95,543	100.0	%	$	66,899	100.0	%	$	256,904	100.0	%	$	176,842	100.0	%

Refinery operating expenses

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	Amount		per bbl		Amount		per bbl		Amount		per bbl		Amount		per bbl
	(in thousands, except per bbl amounts)
Blue Dolphin's direct operating expenses	$	1,033		0.85	$	1,674		1.46	$	4,175		1.22	$	5,927		1.84
LEH operating fee		52		0.04		84		0.07		209		0.06		296		0.09
Total refinery operating expenses	$	1,085	$	0.89	$	1,758	$	1.53	$	4,384	$	1.28	$	6,223	$	1.93

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Jonathan Carroll	$	180	$	171	$	519	$	521
LEH		166		164		489		542
Ingleside		25		23		96		69
	$	371	$	358	$	1,104	$	1,132

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10. Accrued Expenses and Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure Text Block Supplement [Abstract]

Accrued expenses and other current liabilities

	September 30,		December 31,
	2018		2017
	(in thousands)
Board of director fees payable	$	270	$	207
Other payable		205		116
Unearned revenue		125		450
Property taxes		122		131
Customer deposits		109		109
Excise and income taxes payable		32		79
Insurance		-		68
	$	863	$	1,160

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11. Long-Term Debt, Net (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Schedule of Long Term Debt

	September 30,			December 31,
	2018			2017
	(in thousands)
First Term Loan Due 2034 (in default)	$	22,663		$	23,199
Second Term Loan Due 2034 (in default)		9,344			9,502
Notre Dame Debt (in default)		4,978			4,978
Capital leases		51			-
	$	37,036		$	37,679
Less: Current portion of long-term debt, net		(34,988	)		(35,544	)
Less: Unamortized debt issue costs		(2,038	)		(2,135	)
	$	10		$	-

Schedule of Debt issue costs

	September 30,			December 31,
	2018			2017
	(in thousands)
First Term Loan Due 2034 (in default)	$	1,674		$	1,674
Second Term Loan Due 2034 (in default)		768			768
Less: Accumulated amortization		(404	)		(307	)
	$	2,038		$	2,135

Accrued interest related to our long-term debt, net

	September 30,			December 31,
	2018			2017
	(in thousands)
Notre Dame Debt (in default)	$	2,643		$	2,046
BDPL Loan Agreement (related party, in default)		1,374			892
Second Term Loan Due 2034 (in default)		52			49
First Term Loan Due 2034 (in default)		39			40
		4,108			3,027
Less: Interest payable, current portion		(4,108	)		(3,027	)
Long-term interest payable, net of current portion	$	-		$	-

Schedule of summary of equipment held under long-term capital leases

	September 30,			December 31,
	2018			2017
	(in thousands)
Crane	$	94		$	-
Less: accumulated depreciation		(10	)		-
	$	84		$	-

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12. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

	September 30,			December 31,
	2018			2017
	(in thousands)
Asset retirement obligations, at the beginning of the period	$	2,315		$	2,028
Liabilities settled		(1	)		-
Accretion expense		205			287
		2,519			2,315
Less: asset retirement obligations, current portion		(2,519	)		(2,315	)
Long-term asset retirement obligations, at the end of the period	$	-		$	-

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14. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 2018

Risks and Uncertainties [Abstract]

Percentages of all refined petroleum products sales to total sales

	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	(in thousands)
LPG mix	$	-	0.0	%	$	-	0.0	%	$	3	0.0	%	$	121	0.1	%
Naphtha		24,127	25.5	%		14,266	21.6	%		64,093	25.2	%		41,283	24.9	%
Jet fuel		27,299	28.9	%		20,803	31.5	%		73,415	28.9	%		56,361	32.8	%
HOBM		21,735	23.0	%		17,011	25.7	%		60,594	23.8	%		38,580	19.9	%
AGO		21,307	22.6	%		14,053	21.2	%		56,140	22.1	%		38,323	22.3	%
	$	94,468	100.0	%	$	66,133	100.0	%	$	254,245	100.0	%	$	174,668	100.0	%

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16. Income Taxes (Tables)

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income tax benefit (expense)

	September 30,		December 31,
	2018		2017
	(in thousands)
Current
Federal	$	108	$	-
State		43		-
Deferred
Impact of change in enacted tax rates		-		(6,654	)
Change in valuation allowance		109		6,654
Total provision for income taxes	$	260	$	-

Deferred tax assets and deferred tax liabilities

	September 30,			December 31,
	2018			2017
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	11,814		$	9,767
Accrued arbitration award payable		3,048			4,122
Start-up costs (crude oil and condensate processing facility)		699			763
Asset retirement obligations liability/deferred revenue		6			495
AMT credit and other		15			217
Total deferred tax assets		14,033			15,365
Deferred tax liabilities:
Basis differences in property and equipment		(4,936	)		(4,415	)
Total deferred tax liabilities		(4,936	)		(4,415	)
		9,097			10,950
Valuation allowance		(10,538	)		(10,950	)
Deferred tax assets, net	$	108		$	-

NOL carryforwards

	Net Operating Loss Carryforward
	Pre-Ownership Change		Post-Ownership Change		Total
	(in thousands)
Balance at December 31, 2016	$	9,614	$	23,562	$	33,176
Net operating losses		-		6,656		6,656
Balance at December 31, 2017	$	9,614	$	30,218	$	39,832
Net operating losses		-		9,747		9,747
Balance at September 30, 2018	$	9,614	$	39,965	$	49,579

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17. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Earnings per share

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018		2017
	(in thousands, except share and
	per share amounts)
Net income (loss)	$	(937	)	$	3,946	$	748	$	(23,298	)
Basic and diluted income (loss) per share	$	(0.09	)	$	0.36	$	0.07	$	(2.19	)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,925,513			10,818,371		10,925,513		10,644,654

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1. Organization (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss)	$ (937)	$ 3,946	$ 748	$ (23,298)
Net Loss per common share	$ (0.09)	$ 0.36	$ 0.07	$ (2.19)
Working capital deficit current portion	$ (71,000)		$ (71,000)		$ (69,500)
Working capital deficit payment of Operations	$ (29,500)		$ (29,500)		$ (30,000)

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3. Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Accounting Policies [Abstract]
Restricted cash (current portion)	$ 49		$ 49		$ 49
Restricted cash, noncurrent	1,602		1,602		$ 1,602
Gain on the disposal of property	$ 0	$ 0	$ 0	$ 1,834

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4. Business Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net revenues (excluding intercompany fees and sales)	$ 95,543	$ 66,899	$ 256,904	$ 176,842
General and administrative expenses	929	1,240	2,277	2,854
Depreciation and amortization	(30)	(30)	(100)	(100)
Net income (loss)	(937)	3,946	748	(23,298)
Refinery Operations [Member]
Net revenues (excluding intercompany fees and sales)	94,468	66,899	254,245	176,842
Intercompany fees and sales	(873)	0	(2,419)	0
Cost of materials and other	(92,571)	(58,786)	(244,380)	(189,525)
Operating expenses (excluding depreciation and amortization? and general and administrative expenses presented below)	(1,085)	(1,758)	(3,698)	(6,223)
Segment contribution margin	(61)	6,355	3,748	(18,906)
General and administrative expenses	(375)	(913)	(929)	(1,960)
Depreciation and amortization	(432)	(452)	(1,258)	(1,348)
Capital expenditures	372	539	1,141	3,428
Identifiable assets	51,816	70,792	51,816	70,792
Tolling and Terminaling [Member]
Net revenues (excluding intercompany fees and sales)	1,075	0	2,659
Intercompany fees and sales	873	0	2,419
Cost of materials and other	0	0	0
Operating expenses (excluding depreciation and amortization? and general and administrative expenses presented below)	(624)	(140)	(2,092)
Segment contribution margin	1,324	(140)	2,986
General and administrative expenses	(65)	(327)	(156)
Depreciation and amortization	(46)	(3)	(138)
Capital expenditures	223	0	767
Identifiable assets	19,425	2,068	19,425
Corporate & Other [Member]
Net revenues (excluding intercompany fees and sales)	0		0	0
Intercompany fees and sales	0		0	0
Cost of materials and other	0		0	0
Operating expenses (excluding depreciation and amortization? and general and administrative expenses presented below)	(94)		(338)	(399)
Segment contribution margin	(94)		(338)	(399)
General and administrative expenses	(489)		(1,192)	(894)
Depreciation and amortization	0		0	(8)
Capital expenditures	0		0	0
Identifiable assets	926		926	2,068
Total
Net revenues (excluding intercompany fees and sales)	95,543	66,899	256,904	176,842
Intercompany fees and sales	0	0	0	0
Cost of materials and other	(92,571)	(58,786)	(244,380)	(189,525)
Operating expenses (excluding depreciation and amortization? and general and administrative expenses presented below)	(1,803)	(1,898)	(6,128)	(6,622)
Segment contribution margin	1,169	6,215	6,396	(19,305)
General and administrative expenses	(929)	(1,240)	(2,277)	(2,854)
Depreciation and amortization	(478)	(455)	(1,396)	(1,356)
Interest and other non-operating income (expenses)	(742)	(574)	(2,235)	217
Income (loss) before income taxes	(980)	3,496	488	(23,298)
Income tax benefit	43	0	260	0
Net income (loss)	(937)	3,496	748	(23,298)
Capital expenditures	595	539	1,908	3,428
Identifiable assets	$ 72,167	$ 72,860	$ 72,167	$ 72,860

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6. Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 408	$ 294
Other prepaids	39	0
Prepaid crude oil and condensate	0	913
Prepaid expenses, net	$ 447	$ 1,207

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7. Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and condensate	$ 1,571	$ 961
AGO	449	213
HOBM	256	1,558
Naphtha	234	170
Chemicals	94	162
Propane	18	17
LPG mix	5	8
Inventories, net	$ 2,627	$ 3,089

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8. Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 54,210	$ 51,432
Land	566	566
Other property and equipment	747	653
Property, Plant and Equipment, Gross	55,523	52,651
Less: Accumulated depletion, depreciation and amortization	(9,892)	(8,495)
Property, plant and equipment, gross	45,631	44,156
Construction in progress	19,478	20,441
Property, plant and equipment, net	$ 65,109	$ 64,597

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8. Property, Plant and Equipment, Net (Details Narrative) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 4,200	$ 3,900

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9. Related Party Transactions (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Prepaid operating expenses, related party	$ 6,532	$ 5,608
Less: Long-term debt - current portion, related party	(6,532)	(4,000)
Long-term debt - net of current portion, related party	0	1,608
LEH [Member]
Prepaid operating expenses, related party	4,303	4,000
Ingleside [Member]
Prepaid operating expenses, related party	1,263	1,169
Jonathan Carroll [Member]
Prepaid operating expenses, related party	$ 966	$ 439

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9. Related Party Transactions (Details 1) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Total revenues	$ 95,543	$ 66,899	$ 256,904	$ 176,842
Total revenues, percent	100.00%	100.00%	100.00%	100.00%
LEH [Member]
Refinery operations revenues	$ 24,299	$ 20,803	$ 73,415	$ 59,786
Tolling and terminaling revenues	$ 0	$ 56	$ 0	$ 675
Refinery operations revenues, percent	28.70%	31.10%	28.60%	33.80%
Tolling and terminaling revenues, percent	0.00%	0.10%	0.00%	0.40%
Other Customers [Member]
Refinery operations revenues	$ 67,169	$ 45,330	$ 180,830	$ 114,882
Tolling and terminaling revenues	$ 1,075	$ 710	$ 2,659	$ 1,499
Refinery operations revenues, percent	70.40%	67.80%	70.40%	65.00%
Tolling and terminaling revenues, percent	0.90%	1.00%	1.00%	0.80%

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9. Related Party Transactions (Details 2) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($) $ / bbl	Sep. 30, 2017 USD ($) $ / bbl	Sep. 30, 2018 USD ($) $ / bbl	Sep. 30, 2017 USD ($) $ / bbl
Refinery operating expenses, Amount | $	$ 1,085	$ 1,758	$ 4,384	$ 6,223
Refinery operating expenses, Per bbl | $ / bbl	.89	1.53	1.28	1.93
Blue Dolphin's Direct Operating [Member]
Refinery operating expenses, Amount | $	$ 1,033	$ 1,674	$ 4,175	$ 5,927
Refinery operating expenses, Per bbl | $ / bbl	.85	1.46	1.22	1.84
LEH [Member]
Refinery operating expenses, Amount | $	$ 52	$ 84	$ 209	$ 296
Refinery operating expenses, Per bbl | $ / bbl	.04	.07	.06	.09

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9. Related Party Transactions (Details 3) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Interest expenses under loan and guarantee, related party	$ 371	$ 358	$ 1,104	$ 1,132
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	180	171	519	521
LEH [Member]
Interest expenses under loan and guarantee, related party	166	164	489	542
Ingleside [Member]
Interest expenses under loan and guarantee, related party	$ 25	$ 23	$ 96	$ 69

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9. Related Party Transactions (Details Narrative) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Prepaid related party operating expenses	$ 6,532	$ 5,608
Accounts payable, related party	1,378	974
Jonathan Carroll [Member]
Prepaid related party operating expenses	966	439
Ingleside [Member]
Prepaid related party operating expenses	1,263	1,169
LEH [Member]
Prepaid related party operating expenses	$ 4,303	$ 4,000

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10. Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Disclosure Text Block Supplement [Abstract]
Board of director fees payable	$ 270	$ 207
Other payable	205	116
Unearned revenue	125	450
Property taxes	122	131
Customer deposits	109	109
Excise and income taxes payable	32	79
Insurance	0	68
Accrued Expenses and Other Current Liabilities, Net	$ 863	$ 1,160

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11. Long-Term Debt, Net (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Principal balance outstanding	$ 37,036	$ 37,679
Less: Current portion of long-term debt, net	(34,988)	(35,544)
Less: Unamortized debt issue costs	(2,038)	(2,135)
Long term debt	10	0
First Term Loan Due 2034 [Member]
Principal balance outstanding	22,663	23,199
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,344	9,502
Notre Dame Debt [Member]
Principal balance outstanding	4,978	4,978
Capital Leases [Member]
Principal balance outstanding	$ 51	$ 0

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11. Long-Term Debt, Net (Details 1) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 1,674	$ 1,674
Second Term Loan Due 2034	768	768
Less: Accumulated amortization	(404)	(307)
Long term debt	$ 2,038	$ 2,135

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11. Long-Term Debt, Net (Details 2) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Long-term Debt Net Details 2
Notre Dame Debt (in default)	$ 2,643	$ 2,046
BDPL Loan Agreement (related party, in default)	1,374	892
Second Term Loan Due 2034	52	49
First Term Loan Due 2034	39	40
Total	4,108	3,027
Less: Interest payable, current portion	(4,108)	(3,027)
Long term debt	$ 0	$ 0

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11. Long-Term Debt, Net (Details 3) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Crane	$ 94	$ 0
Less: accumulated depreciation	(10)	0
Capital lease obligation	$ 84	$ 0

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11. Long-Term Debt, Net (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Amortization expense	$ 30	$ 30	$ 100	$ 100
First Term Loan Due 2034
Guaranty fees	100	100	300	400
Second Term Loan Due 2034
Guaranty fees	$ 50	$ 50	$ 100	$ 100

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12. Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period			$ 2,315	$ 2,028	$ 2,028
Liabilities settled			(1)		0
Accretion expense	$ 61	$ 72	205	$ 216	287
Asset retirement obligations	2,519		2,519		2,315
Less: asset retirement obligations, current portion	(2,519)		(2,519)		(2,315)
Long-term asset retirement obligations, at the end of the period	$ 0		$ 0		$ 0

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13. Treasury Stock (Details Narrative) - shares	Sep. 30, 2018	Dec. 31, 2017
Equity [Abstract]
Treasury stock	0	0

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14. Concentration of Risk (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Total refined petroleum product sales	$ 94,468	$ 66,133	$ 254,245	$ 174,668
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 0	$ 0	$ 3	$ 121
Concentration Risk	0.00%	0.00%	0.00%	0.10%
Naphtha
Total refined petroleum product sales	$ 24,127	$ 14,266	$ 64,093	$ 41,283
Concentration Risk	25.50%	21.60%	25.20%	24.90%
Jet Fuel
Total refined petroleum product sales	$ 27,299	$ 20,803	$ 73,415	$ 56,361
Concentration Risk	28.90%	31.50%	28.90%	32.80%
HOBM
Total refined petroleum product sales	$ 21,735	$ 17,011	$ 60,594	$ 38,580
Concentration Risk	23.00%	25.70%	23.80%	19.90%
AGO
Total refined petroleum product sales	$ 21,307	$ 14,053	$ 56,140	$ 38,323
Concentration Risk	22.60%	21.20%	22.10%	22.30%

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14. Concentration of Risk (Details Narrative) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Risks and Uncertainties [Abstract]
FDIC insurance limit	$ 1,200	$ 1,600

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15. Leases (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Leases, Operating [Abstract]
Rent expense	$ 30	$ 30	$ 100	$ 100

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16. Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Taxes Details Abstract
Current federal			$ 108		$ 0
Current state			43		0
Impact of change in enacted tax rates			0		(6,654)
Change in valuation allowance			109		6,654
Total provision for income taxes	$ (43)	$ 0	$ (260)	$ 0	$ 0

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16. Income Taxes (Details 1) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 11,814	$ 9,767
Accrued arbitration award payable	3,048	4,122
Start-up costs (crude oil and condensate processing facility)	699	763
Asset retirement obligations liability/deferred revenue	6	495
AMT credit and other	15	217
Total deferred tax assets	14,033	15,365
Deferred tax liabilities:
Basis differences in property and equipment	(4,936)	(4,415)
Total deferred tax liabilities	(4,936)	(4,415)
Deferred tax assets, net	9,097	10,950
Valuation allowance	(10,538)	(10,950)
Deferred tax assets, net	$ 108	$ 0

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16. Income Taxes (Details 2) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Beginning balance	$ 39,832	$ 33,176
Net operating losses	9,747	6,656
Ending balance	49,579	39,832
Pre-Ownership Change [Member]
Beginning balance	9,614	9,614
Net operating losses	0	0
Ending balance	9,614	9,614
Post-Ownership Change [Member]
Beginning balance	30,218	23,562
Net operating losses	9,747	6,656
Ending balance	$ 39,965	$ 30,218

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16. Income Taxes (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Benefit	$ (43)	$ 0	$ (260)	$ 0	$ 0

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17. Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Net income (loss)	$ (937)	$ 3,946	$ 748	$ (23,298)
Basic and diluted income per share	$ (.09)	$ .36	$ .07	$ (2.19)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,925,513	10,818,371	10,925,513	10,644,654