10-Q

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, 2019

 or

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

For the transition period from to

Commission File No. 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware	73-1268729
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
801 Travis Street, Suite 2100, Houston, Texas	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) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒ No ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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	☐	Smaller reporting company	☒
		Emerging growth company	☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

Number of shares of common stock, par value $0.01 per share outstanding as of November 14, 2019: 12,327,365

1

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

TABLE OF CONTENTS

GLOSSARY OF SELECTED ENERGY, FINANCIAL, AND OTHER 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	37
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
ITEM 4.	CONTROLS AND PROCEDURES	49
PART II.	OTHER INFORMATION	50
ITEM 1.	LEGAL PROCEEDINGS	50
ITEM 1A.	RISK FACTORS	50
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	50
ITEM 4.	MINE SAFETY DISCLOSURES	51
ITEM 5.	OTHER INFORMATION	51
ITEM 6.	EXHIBITS	51
SIGNATURES		52

2

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

INTRODUCTION

This Quarterly Report for the period ended September 30, 2019 (this “Quarterly Report”) is a document that U.S. public companies file with the Securities and Exchange Commission (“SEC”) on a periodic basis. 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. Information in this Quarterly Report is current as of the filing date, unless otherwise specified.

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; 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, 2018 (the “Annual Report”), and “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the period ended March 31, 2019, our Quarterly Report on Form 10-Q for the period ended June 30, 2019, and this Quarterly Report explain some of the important factors that may cause actual results to be materially different from those that we anticipate.

3

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

 

GLOSSARY OF SELECTED ENERGY, FINANCIAL, AND OTHER TERMS

Below are abbreviations and definitions of certain commonly used oil and gas industry terms, as well as key financial performance measures used by management, that are used in this 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 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between 5 and 15 carbon atoms per molecule.   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.

4

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Product Slate. Represents type and quality of products produced.  Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquified petroleum gases. Others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. Refined 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 by-product of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized per their sulfur content, with lower sulfur fuels usually selling at a higher, or premium, price and higher sulfur fuels selling at a lower, or discounted, price. Topping unit. A type of petroleum refinery that engages in only the first step of the refining process -- crude distillation. A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0. 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). Cost of Goods Sold. Reflects the cost of crude oil and condensate, fuel use, and chemicals. 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. Gross Margin. Calculated as gross profit divided by total revenue; reflected as a percentage (%). Gross Profit.Calculated as total revenue less cost of goods sold; reflected as a dollar ($) amount. Operating Days. Represents the number of days in a period in which the crude distillation tower operated. Operating days is calculated by subtracting downtime in a period from calendar days in the same period.	Other conversion costs. Represents the combination of direct labor costs and manufacturing overhead costs. These are the costs that are necessary to convert our raw materials into refined petroleum products. Other Operating Expenses. Represents costs associated with our pipeline assets and leasehold interests in oil and gas properties. Refining Gross Profit per Bbl. Calculated as refinery operations revenue less total cost of goods sold divided by the volume, in bbls, of refined petroleum products sold during the period; reflected as a dollar ($) 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.
Other Defined Terms
Final Arbitration Award. Damages and attorney fees and related expenses awarded to GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, L.P. (“Genesis”) by an arbitrator on August 11, 2017 (the “Final Arbitration Award”), in arbitration proceedings between LE and GEL (the “GEL Arbitration”) 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 dated August 12, 2011.	Settlement Agreement. 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 that certain Settlement Agreement with GEL (as may be further amended, restated, supplemented or otherwise modified from time to time, 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 was conditioned upon the Lazarus Parties paying GEL a lump sum cash payment of $10.0 million (the “Settlement Payment”) by a certain date (the “Settlement Date”) and $0.5 million in cash at the end of each calendar month (the “Interim Payments”) until the Settlement Payment was made.

Remainder of Page Intentionally Left Blank

5

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

  

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	September 30,	December 31,
	2019	2018
	(in thousands except share amounts)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$584	$14
Restricted cash	49	49
Accounts receivable, net	336	379
Accounts receivable, related party	321	-
Prepaid expenses and other current assets	1,264	1,786
Deposits	162	194
Inventory	1,734	1,510
Refundable federal income tax	166	108
Total current assets	4,616	4,040
LONG-TERM ASSETS
Total property and equipment, net	64,412	64,697
Operating lease right-of-use assets	685	-
Restricted cash, noncurrent	547	1,602
Surety bonds	230	230
Deferred tax assets, net	50	108
Total long-term assets	65,924	66,637
TOTAL ASSETS	$70,540	$70,677
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default	$34,151	$34,863
Line of credit payable	12,180	-
Long-term debt, related party, current portion, in default	7,918	7,041
Accrued interest payable (in default)	3,834	2,939
Accrued interest payable, related party (in default)	2,014	1,534
Accounts payable	2,265	2,719
Accounts payable, related party	2,042	1,529
Current portion of lease liabilities	262	-
Asset retirement obligations, current portion	2,580	2,580
Accrued expenses and other current liabilities	2,296	1,571
Accrued arbitration award payable	-	21,128
Total current liabilities	69,542	75,904
LONG-TERM LIABILITIES
Long-term lease liabilities, net of current	610	-
Total long-term liabilities	610	-
TOTAL LIABILITIES	70,152	75,904
Commitments and contingencies (Note 18)
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,975,514
shares issued at September 30, 2019 and December 31, 2018)	110	110
Additional paid-in capital	36,936	36,936
Accumulated deficit	(36,658)	(42,273)
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)	388	(5,227)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$70,540	$70,677

See accompanying notes to consolidated financial statements.

6

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
	(in thousands, except share and per-share amounts)
REVENUE FROM OPERATIONS
Refinery operations	$77,537	$94,468	$222,652	$254,245
Tolling and terminaling	1,096	1,075	3,253	2,659
Total revenue from operations	78,633	95,543	225,905	256,904
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	74,163	92,167	213,714	243,245
Other conversion costs	2,066	1,959	6,587	6,463
Total cost of goods sold	76,229	94,126	220,301	249,708
Gross profit	2,404	1,417	5,604	7,196
COST OF OPERATIONS
LEH operating fee	144	154	477	462
Other operating expenses	52	33	165	133
General and administrative expenses	655	929	1,904	2,277
Depletion, depreciation and amortization	632	478	1,855	1,396
Accretion of asset retirement obligations	-	61	-	205
Total cost of operations	1,483	1,655	4,401	4,473
Income (loss) from operations	921	(238)	1,203	2,723
OTHER INCOME (EXPENSE)
Easement, interest and other income	1	18	2	20
Interest and other expense	(1,883)	(760)	(4,718)	(2,255)
Gain on extinguishment of debt	9,128	-	9,128	-
Total other income (expense)	7,246	(742)	4,412	(2,235)
Income (loss) before income taxes	8,167	(980)	5,615	488
Income tax benefit	-	43	-	260
Net income (loss)	$8,167	$(937)	$5,615	$748
Income (loss) per common share:
Basic	$0.74	$(0.09)	$0.51	$0.07
Diluted	$0.74	$(0.09)	$0.51	$0.07
Weighted average number of common shares outstanding:
Basic	10,975,514	10,925,513	10,975,514	10,925,513
Diluted	10,975,514	10,925,513	10,975,514	10,925,513

See accompanying notes to consolidated financial statements.

7

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2019	2018
	(in thousands)
OPERATING ACTIVITIES
Net income	$5,615	$748
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization	1,855	1,396
Deferred income tax	-	(216)
Amortization of debt issue costs	409	96
Guaranty fees paid in kind	471	-
Accretion of asset retirement obligations	-	205
Gain on extinguishment of debt	(9,128)	-
Changes in operating assets and liabilities
Accounts receivable	43	(312)
Accounts receivable, related party	(321)	653
Prepaid expenses and other current assets	522	760
Deposits and other assets	32	(65)
Inventory	(224)	462
Accrued arbitration award	(12,000)	(4,000)
Accounts payable, accrued expenses and other liabilities	1,689	1,023
Accounts payable, related party	513	404
Net cash provided by (used in) operating activities	(10,524)	1,154
INVESTING ACTIVITIES
Capital expenditures	(1,458)	(1,826)
Net cash used in investing activities	(1,458)	(1,826)
FINANCING ACTIVITIES
Proceeds from line of credit	12,402	-
Payments on debt	(990)	(723)
Payments of debt issuance costs	(322)	-
Net activity on related-party debt	(407)	924
Net cash provided by financing activities	11,497	201
Net change in cash, cash equivalents, and restricted cash	(485)	(471)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	1,665	2,146
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$1,180	$1,675
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable and finance leases	$86	$82
Line of credit closing costs included in principal balance	$398	$-
Interest paid	$2,261	$2,173
Income taxes paid	$-	$-

See accompanying notes to consolidated financial statements.

8

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
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 in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and more than 1.0 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 owned 79.8% of our common stock, par value $0.01 per share (the “Common Stock”) at September 30, 2019. (See “Note (9) Related-Party Transactions,” “Note (11) Long-Term Debt and Accrued Interest” 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”).

See “Part I, Item 1. Business” and “Part I, Item 2. Properties” in our 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:

Defaults Under Veritex Secured Loan Agreements. LE and LRM each have loans with Veritex Community Bank (“Veritex”), as successor in interest to Sovereign Bank (“Sovereign”) by merger, in the original aggregate amount of $35.0 million. These Veritex loans are guaranteed 100% by the U.S. Department of Agriculture (“USDA”).

●

Events of Default. Veritex delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constituted an event of default under the secured loan agreements. The occurrence of an event of default permitted 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 did not accelerate or call due the secured loan agreements considering the Settlement Agreement. Instead, 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.

●

Financial Covenant Defaults. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2019, 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.

9

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at September 30, 2019 and December 31, 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.

Veritex worked with LE and LRM and was aware and party to all discussions and arrangements with GEL surrounding the Settlement Agreement, all amendments, and the final and effective Settlement with GEL. In a notice to obligors dated April 30, 2019 (the "Veritex Consent'), Veritex agreed to waive certain covenant defaults and forbear from enforcing its remedies under the secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of a payment reserve account in the amount of $1.0 million as required by one of the secured loan agreements on or before August 31, 2019. As of the filing date of this Quarterly Report, the payment reserve account had not been fully replenished. Any exercise by Veritex of its rights and remedies under such secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

Net Losses and Working Capital Deficits. For the three months ended September 30, 2019, we reported net income of $8.2 million, or $0.74 per share. Excluding the $9.1 million gain on extinguishment of debt, we would have reported a net loss of $1.0 million, or a loss of $0.09 per share, for the three months ended September 30, 2019. Comparatively, we reported a net loss of $0.9 million, or a loss of $0.09 per share, for the three months ended September 30, 2018.

For the nine months ended September 30, 2019, we reported net income of $5.6 million, or $0.51 per share. Excluding the $9.1 million gain on extinguishment of debt, we would have reported a net loss of $3.5 million, or $0.32 per share, for the nine months ended September 30, 2019. This compares to reported net income of $0.7 million, or income of $0.07 per share, for the nine months ended September 30, 2018.

We had a working capital deficit of $64.9 million and $71.9 million at September 30, 2019 and December 31, 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $22.9 million and $30.0 at September 30, 2019 at December 31, 2018, respectively.

For additional disclosures related to defaults under secured loan agreements and other long-term debt, see “Item 1. Financial Statements – Note (11) Long-Term Debt and Accrued Interest” and “ – Note (9) Related Party Transactions” in this Quarterly Report. For additional disclosures related to the Settlement Agreement, refer to “Item 1. Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Final Arbitration Award and Settlement Agreement” in the Quarterly Report, as well as “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the period ended December 31, 2018 (the “Annual Report”).

Operating Risks. Successful execution of our business strategy depends on several key factors, including, having adequate working capital to meet operational needs and regulatory requirements, maintaining safe and reliable operations at the Nixon Facility, meeting contractual obligations, and having favorable margins on refined petroleum products. During the three months ended September 30, 2019, management successfully finalized the Settlement with GEL and realized a $9.1 million gain on the extinguishment of the liability, and management believes that it is continuing to take other steps to further improve our operations and financial stability. However, there can be no assurance that our business strategy 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 or meet financial assurance (bonding) requirements on commercially reasonable terms or at all. If Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

For additional disclosures related to our business strategy and risk factors that could materially affect our future business, financial condition and results of operations, refer to “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Results of Operations” and “Liquidity and Capital Resources” in this Quarterly Report, as well as “Part I, Item 1. Business – Business Strategy,” “Part I, Item 1A. Risk Factors,” and “Part I, Item 3. Legal Proceedings” in our Annual Report.

10

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

(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 Article 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, 2018 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, 2019 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2019, 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 a payment reserve account held by Veritex as security for payments under a loan agreement. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of construction related expenses to complete building new petroleum storage tanks.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are presented net of any necessary allowance(s) for doubtful accounts. Receivables are recorded at the invoiced amount and generally do not bear interest. An allowance for doubtful accounts is established, when necessary, based on prior experience and other factors which, in management's judgment, deserve consideration in estimating bad debts.  Management assesses collectability primarily based on the current aging status of the customer's account, our historical collection experience with the customer, and the customer's financial condition.  Based on a review of these factors, management establishes or adjusts the allowance for specific customers and the accounts receivable portfolio as a whole.  We had an allowance for doubtful accounts of $0.1 million at both September 30, 2019 and December 31, 2018.

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

11

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
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.

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for the periods presented.

Pipelines and Facilities. Our pipelines and facilities are recorded at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with 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, including capitalized interest, relate to construction and refurbishment activities at the Nixon Facility. These expenditures 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.)

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

12

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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 the sale and when payment is due is not significant. Transportation, shipping, and handling costs incurred are included in cost of goods sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tolling and Terminaling Revenue. Tolling and terminaling represents 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 cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2019 and December 31, 2018. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”) credit carryforwards. In addition, we have NOL carryforwards that remain available for future use.

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, 2019 and December 31, 2018, 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.)

13

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented.

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. The cost estimates for each of our assets were developed based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (13) 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.)

14

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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:

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

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

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

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

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

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

15

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (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 Staff Accounting Bulletin No. 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act in the period of enactment.  This guidance also includes amendments to the XBRL Taxonomy.  For public business entities, the amendments in ASU 2018-05 are effective for fiscal years ending after December 15, 2020. Early adoption is permitted.  We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

(4) Revenue and Segment Information

We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility.

Revenue from Contracts with Customers.

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

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

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

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

	Three Months Ended September 30,
	2019				2018
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Tolling and	Corporate
	Operations	Terminaling	& Other	Total	Operations	Terminaling	& Other	Total
Net revenues (excluding intercompany fees and sales)	$77,537	$1,096	$-	$78,633	$94,468	$1,075	$-	$95,543
Intercompany fees and sales	(668)	668	-	-	(873)	873	-	-
Operation costs and expenses(1)	(76,088)	(285)	(52)	(76,425)	(93,656)	(624)	(94)	(94,374)
Segment contribution margin	$781	$1,479	$(52)	$2,208	$(61)	$1,324	$(94)	$1,169
General and administrative expenses	(292)	(68)	(295)	(655)	(375)	(65)	(489)	(929)
Depreciation and amortization	(481)	(99)	(52)	(632)	(432)	(46)	-	(478)
Interest and other non-operating income (expenses), net				7,246				(742)
Income (loss) before income taxes				8,167				(980)
Income tax benefit				-				43
Net income (loss)				$8,167				$(937)
Capital expenditures	$964	$-	$-	$964	$372	$223	$-	$595
Identifiable assets	$49,613	$18,994	$1,933	$70,540	$51,816	$19,425	$926	$72,167

(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 use costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

16

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

	Nine Months Ended September 30,
	2019				2018
	(in thousands)
	Segments				Segment
	Refinery	Tolling and	Corporate		Refinery	Tolling and	Corporate
	Operations	Terminaling	& Other	Total	Operations	Terminaling	& Other	Total
Net revenues (excluding intercompany fees and sales)	$222,652	$3,253	$-	$225,905	$254,245	$2,659	$-	$256,904
Intercompany fees and sales	(1,927)	1,927	-	-	(2,419)	2,419	-	-
Operation costs and expenses(1)	(219,766)	(1,012)	(165)	(220,943)	(248,078)	(2,092)	(338)	(250,508)
Segment contribution margin	$959	$4,168	$(165)	$4,962	$3,748	$2,986	$(338)	$6,396
General and administrative expenses	(898)	(173)	(833)	(1,904)	(929)	(156)	(1,192)	(2,277)
Depreciation and amortization	(1,429)	(297)	(129)	(1,855)	(1,258)	(138)	-	(1,396)
Interest and other non-operating income (expenses), net				4,412				(2,235)
Income before income taxes				5,615				488
Income tax benefit				-				260
Net income				$5,615				$748
Capital expenditures	$1,375	$83	$-	$1,458	$1,141	$767	$-	$1,908
Identifiable assets	$49,613	$18,994	$1,933	$70,540	$51,816	$19,425	$926	$72,167

(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 use costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

(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,
	2019	2018
	(in thousands)
Prepaid insurance	$537	$437
Prepaid crude oil and condensate	525	1,166
Prepaid easement renewal fees	127	143
Other prepaids	75	40
	$1,264	$1,786

(7) Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,	December 31,
	2019	2018
	(in thousands)
Crude oil and condensate	$1,177	$861
AGO	285	276
Chemicals	142	106
Naphtha	99	143
Propane	25	17
LPG mix	6	5
HOBM	-	102
	$1,734	$1,510

17

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

(8) Property, Plant and Equipment, Net

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

	September 30,	December 31,
	2019	2018
	(in thousands)
Refinery and facilities	$66,308	$63,058
Land	566	566
Other property and equipment	833	747
	67,707	64,371
Less: Accumulated depletion, depreciation, and amortization	(12,156)	(10,429)
	55,551	53,942
Construction in progress	8,861	10,755
	$64,412	$64,697

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 $0.7 million and $1.3 million at September 30, 2019 and December 31, 2018, respectively. Capital expenditures at the Nixon Facility are being funded by working capital derived from revenue from operations and LEH and its affiliates (including Jonathan Carroll), as well as from long-term debt from Veritex that was secured in 2015 for expansion of the Nixon Facility. Unused amounts under the Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. See “Note (11) Long-Term Debt and Accrued Interest” for additional disclosures related to borrowings for capital spending.

(9) Related-Party Transactions

Related Parties. 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-party transactions consist of the following 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 owned 79.8% of our Common Stock at September 30, 2019. 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) an office sublease-agreement with BDSC.

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 Texas Refinery I, LLC (“LTRI”). LTRI is a related party of LEH and Jonathan Carroll. During the quarter ended September 30, 2019, LE purchased refurbished refinery equipment from LTRI for use at the Nixon Facility.

Lazarus Marine Terminal I, LLC (“LMT”). LMT is a related party of LEH and Jonathan Carroll. LE was party to a Dock Tolling Agreement with LMT that was terminated during the quarter ended September 30, 2019.

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. The guaranty fee agreements and the promissory note relate to LE and LRM USDA-guaranteed loans.

18

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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) on 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. The Board plans to review the Amended and Restated Operating Agreement during the first quarter of 2020 to evaluate renewal.

LEH receives a management fee calculated as 5% of certain of our direct operating expenses. During the fourth quarter of 2018, the management fee was changed to be calculated based on year to date operating expenses incurred, regardless of whether they were paid for by LEH or LE. The management fee was previously reflected within refinery operating expenses in our consolidated statements of operations. The management fee is currently reflected as the ‘LEH operating fee’ 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, 2020 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.

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 had a five-year term. Under the agreement, LE paid LMT a flat reservation fee monthly. The reservation fee included tolling volumes up to 84,000 gallons per day. Excess tolling volumes were subject to an increased per gallon rate. The Dock Tolling Agreement was terminated effective July 1, 2019. Amounts expensed as tolling fees under the Dock Tolling Agreement are reflected in cost of goods sold in our consolidated statements of operations.

Office Sub-Lease Agreement. In January 2018, BDSC entered into an Office Space Agreement with LEH to lease office space at our headquarters building in Houston, Texas. The Office Space Agreement has a term of sixty-eight (68) months expiring on August 31, 2023. Under the Office Space Agreement, LEH’s base rent is approximately $0.02 million per month. The Office Space Agreement includes rent abatement periods.

Refinery Equipment Purchase. In July 2019, LE purchased two (2) refurbished heat exchangers from LTRI. The total purchase price was $160,000. The cost is reflected in accounts payable, related party in our consolidated balance sheets.

Financial Agreements. We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. LEH and its affiliates (Ingleside and Jonathan Carroll) have provided working capital to Blue Dolphin in the form of a term loan and non-cash advances (such as conversion of accounts payable to debt under 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 financial agreements are reflected in long-term debt, related party, current portion in our consolidated balance sheets.

BDPL Loan Agreement (In Default). BDPL has a 2016 loan agreement and related security agreement with LEH as lender (the “BDPL Loan Agreement”). The BDPL Loan Agreement is currently in default due to non-payment. Key terms of the BDPL Loan Agreement are as follow:

Principal Amount:	$4.0 million
Maturity Date:	August 2018
Principal and Interest Payment:	$500,000 annually
Interest Rate:	16.00%

19

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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 accrued interest payable, related party, current portion in our consolidated balance sheets. To date, there have been no payments under the BDPL Loan Agreement.

Promissory Notes (In Default). Working capital provided to Blue Dolphin in the form of non-cash advances whereby accounts payable, related party was converted to debt under promissory notes are reflected below. The promissory notes matured in January 2019. Interest, which is compounded annually, is still accruing at a rate of 8.00% and is reported as part of the outstanding balance. Promissory notes to LEH, Ingleside and Jonathan Carroll, which are reflected within long-term debt, related party, are currently in default.

●

June LEH Note. The June LEH Note reflects amounts owed to LEH at September 30, 2019 under the Amended and Restated Operating Agreement.

●

March Ingleside Note. The March Ingleside Note reflects amounts owed to Ingleside at September 30, 2019 under the Amended and Restated Tank Lease Agreement.

●

March Carroll Note. The March Carroll Note reflects amounts owed to Jonathan Carroll at September 30, 2019 under the guaranty fee agreements. See “Amended and Restated Guaranty Fee Agreements” below for additional information.

Amended and Restated Guaranty Fee Agreements. Jonathan Carroll was required to provide a guarantee for repayment of funds borrowed and interest accrued under certain LE and LRM USDA-guaranteed loans. For his personal guarantee, LE and LRM each 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 loan agreements. Effective in April 2017, the Guaranty Fee Agreements were amended and restated (the “Amended and Restated Guaranty Fee Agreements”) to reflect payment 50% in cash and 50% in Blue Dolphin Common Stock. Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, current portion in our consolidated balance sheets. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

As previously disclosed, the Lazarus Parties were prohibited by GEL from making payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements (see also “Note (18) Commitments and Contingencies – Legal Matters – Final Arbitration Award and Settlement Agreement”). Now that the Settlement between GEL and the Lazarus Parties is final and effective, management has resumed payments of the common stock component to Mr. Carroll under the agreements. On November 14, 2019, Mr. Carroll received 1,351,851 shares of Common Stock, which represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019. Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. Currently, management does not intend on paying Mr. Carroll the cash portion due to Blue Dolphin’s working capital deficits. The cash portion of guaranty fees owed to Mr. Carroll will continue to be accrued and added to the principal balance of the March Carroll Note.

Remainder of Page Intentionally Left Blank

20

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

Financial Statements Impact.

Consolidated Balance Sheets. Accounts payable, related party to LMT associated with the Dock Tolling Agreement totaled $1.8 million and $1.5 million at September 30, 2019 and December 31, 2018, respectively. Accounts payable, related party to LTRI related to the purchase of refinery equipment totaled $0.2 million and $0 at September 30, 2019 and December 31, 2018, respectively.

Long-term debt, related party, current portion and accrued interest payable, related party, as of the dates indicated was as follows:

	September 30,	December 31,
	2019	2018
	(in thousands)
LEH
June LEH Note (in default)	$868	$611
BDPL Loan Agreement (in default)	6,014	5,534
LEH total	6,882	6,145
Ingleside
March Ingleside Note (in default)	1,345	1,283
Jonathan Carroll
March Carroll Note (in default)	1,705	1,147
	9,932	8,575
Less: Long-term debt, related party, current portion, in default	(7,918)	(7,041)
Less: Accrued interest payable, related party (in default)	(2,014)	(1,534)
	$-	$-

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands, except percent amounts)
Refinery operations
LEH	$25,034	31.8%	$27,299	28.7%	$70,016	31.0%	$73,415	28.6%
Other customers	52,503	66.8%	67,169	70.4%	152,636	67.6%	180,830	70.4%
Tolling and terminaling
Other customers	1,096	1.4%	1,075	0.9%	3,253	1.4%	2,659	1.0%
	$78,633	100.0%	$95,543	100.0%	$225,905	100.0%	$256,904	100.0%

Fees associated with the Dock Tolling Agreement with LMT totaled $0.05 million for the three months ended September 30, 2019 compared to $0.2 million for the three months ended September 30, 2018. Fees associated with the Dock Tolling Agreement with LMT totaled $0.4 million and $0.6 million for the nine-month periods ended September 30, 2019 and 2018, respectively.

Lease payments received under the office sub-lease agreement with LEH totaled $0.01 million for the three months ended September 30, 2019 and 2018. Lease payments received under the office sub-lease agreement with LEH totaled $0.03 million for the nine months ended September 30, 2019 and 2018.

The LEH operating fee totaled approximately $0.1 million in the three months ended September 30, 2019 compared to $0.2 million for the three months ended September 30, 2018. For both nine-month periods ended September 30, 2019 and 2018, the LEH operating fee totaled approximately $0.5 million.

21

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
	(in thousands)
Jonathan Carroll
Guaranty Fee Agreements
First Term Loan Due 2034	$110	$114	$333	$344
Second Term Loan Due 2034	46	47	138	141
March Carroll Note (in default)	33	19	86	34
LEH
BDPL Loan Agreement (in default)	160	160	480	482
June LEH Note (in default)	17	6	40	7
Ingleside
March Ingleside Note (in default)	12	25	63	96
	$378	$371	$1,140	$1,104

(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,
	2019	2018
	(in thousands)
Unearned revenue	$1,207	$434
Board of director fees payable	370	273
Insurance	232	61
Other payable	223	265
Property taxes	161	48
Excise and income taxes payable	93	47
Customer deposits	10	109
Easement payable	-	223
Accrued rent	-	111
	$2,296	$1,571

22

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

(11) Long-Term Debt and Accrued Interest

Outstanding Balances. Our Long-term debt consists of: (i) a LE $25.0 million loan with Veritex (the “First Term Loan Due 2034”), (ii) a LRM $10.0 million loan with Veritex (the “Second Term Loan Due 2034”), and (iii) a LE loan with Notre Dame Investors, Inc. as evidenced by a promissory note that is currently held by John Kissick (the “Notre Dame Debt”). As described within this “Note (11”) Long-Term Debt and Accrued Interest,” certain of our long-term debt is currently in default. See “Note (9) Related-Party Transactions” for additional disclosures regarding long-term debt, related party and accrued interest payable, related party.

We adopted new ASU guidance related to leases. As a result, disclosures previously reported in this “Note (11”) Long-Term Debt and Accrued Interest” as capital leases are now reported in “Note (15) Leases” as finance leases. See “Note (3) Significant Accounting Policies – New Pronouncements Adopted” for information related to the new lease accounting standard.

Long-term debt, which represents outstanding principal and accrued interest, as of the dates indicated was as follows:

	September 30,	December 31,
	2019	2018
	(in thousands)
First Term Loan Due 2034 (in default)	$22,178	$22,593
Second Term Loan Due 2034 (in default)	9,197	9,353
Notre Dame Debt (in default)	8,418	7,821
Capital lease	-	41
	$39,793	$39,808
Less: Current portion of long-term debt, net	(34,151)	(34,863)
Less: Unamortized debt issue costs	(1,910)	(2,006)
Less: Accrued interest payable (in default)	(3,732)	(2,939)
	$-	$-

Unamortized debt issue costs related to long-term debt as of the dates indicated consisted of the following:

	September 30,	December 31,
	2019	2018
	(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	(532)	(436)
	$1,910	$2,006

Amortization expense was $0.03 million for the three months ended September 30, 2019 and 2018. Amortization expense was $0.9 million for the nine months ended September 30, 2019 and 2018.

23

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

	September 30,	December 31,
	2019	2018
	(in thousands)
Notre Dame Debt (in default)	$3,440	$2,843
First Term Loan Due 2034 (in default)	182	43
Second Term Loan Due 2034 (in default)	110	53
	3,732	2,939
Less: Accrued interest payable (in default)	(3,732)	(2,939)
Long-term interest payable, net of current portion	$-	$-

USDA-Guaranteed Loans. The First Term Loan Due 2034 and Second Term Loan Due 2034 are guaranteed 100% by the USDA. The USDA, acting through its agencies, administers a federal rural credit program that makes direct loans and guarantees portions of loans made and serviced by USDA-qualified lenders for various purposes. Each USDA guarantee is a full faith and credit obligation of the United States with the USDA guaranteeing up to 100% of the principal amount of guaranteed loans. The lender on each USDA-guaranteed loan is required by regulation to retain the unguaranteed portion of the guaranteed loan, to service the entire underlying guaranteed loan, including the USDA-guaranteed portion and the unguaranteed portion, and to remain mortgage and/or secured party of record. The USDA-guaranteed portion and the unguaranteed portion of the loan are to be secured by the same collateral with equal lien priority. The USDA-guaranteed portion of a loan cannot be paid later than, or in any way be subordinated to, the related unguaranteed portion.

Amended and Restated Guaranty Fee Agreements. As a condition of the First Term Loan Due 2034 and Second Term Loan Due 2034, Jonathan Carroll was required to provide a guarantee for repayment of funds borrowed and interest accrued under the USDA-guaranteed loans. LEH, LRM and Blue Dolphin also cross-guaranteed the First Term Loan Due 2034 and Second Term Loan Due 2034. (See “Note (9) Related-Party Transactions” for additional disclosures related to LEH, Jonathan Carroll, and the Amended and Restated Guaranty Fee Agreements, as well as a breakdown of guaranty fee expenses incurred related to the First Term Loan Due 2034 and Second Term Loan Due 2034.)

Defaults in USDA-Guaranteed Loan Agreements. As described elsewhere in this Quarterly Report, Veritex notified LE and LRM that the Final Arbitration Award constituted an event of default under the First Term Loan Due 2034 and the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2019, 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 First Term Loan Due 2034 and Second Term Loan 2034. LE also failed to replenish a payment reserve account as required under the First Term Loan Due 2034. The occurrence of events of default under the First Term Loan Due 2034 and Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 and Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE and LRM’s obligations under the loan agreements, and/or exercise any other rights and remedies available. Veritex did not accelerate or call due the First Term Loan Due 2034 and Second Term Loan Due 2034 considering the Settlement Agreement. Instead, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and Second Term Loan Due 2034 and informed LE and LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements.

24

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

Veritex worked with LE and LRM and was aware and party to all discussions and arrangements with GEL surrounding the Settlement Agreement, all amendments, and the final and effective Settlement with GEL. In the Veritex Consent, Veritex agreed to waive certain covenant defaults and forbear from enforcing its remedies under the secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of the $1.0 million payment reserve account as required under the First Term Loan Due 2034 on or before August 31, 2019. As of the filing date of this Quarterly Report, the payment reserve account had not been fully replenished. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 and Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations. (See “Note (1) Organization – Going Concern” and “– Operating Risks” for additional disclosures related to the First Term Loan Due 2034 and Second Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

Key Terms of Long-Term Debt.

First Term Loan Due 2034 (In Default). Key terms of the First Term Loan Due 2034 are as follow:

Principal Amount:	$25.0 million
Maturity Date:	June 2034
Principal and Interest Payment:	$0.2 million monthly
Interest Rate:	Wall Street Journal Prime Rate plus 2.75%

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, which is 100% USDA-guaranteed, is secured by: (i) a first lien on the Nixon Facility’s 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.

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.

Second Term Loan Due 2034 (In Default). Key terms of the Second Term Loan Due 2034 are as follow:

Principal Amount:	$10.0 million
Maturity Date:	December 2034
Principal and Interest Payment:	$0.1 million monthly
Interest Rate:	Wall Street Journal Prime Rate plus 2.75%

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, which is 100% USDA-guaranteed, 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 a term loan that matured in 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.

25

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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.

Notre Dame Debt (In Default). Key terms of the Notre Dame Debt are as follow:

Original Principal Amount:	$8.0 million
Additional Principal:	$3.7 million
Maturity Date:	January 2018
Principal and Interest Payment:	None; payment rights subordinated to senior lender
Default Interest Rate:	16.00%

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. 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’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034. To date, there have been no payments under the Notre Dame Debt.

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.

(12) Line of Credit Payable

Line of credit payable consists of a line of credit, guarantee and security agreement between Pilot Travel Centers LLC (“Pilot”) and NPS (the “Pilot Line of Credit”). Pilot and NPS entered the Pilot Line of Credit on May 3, 2019. The parties to the Pilot Line of Credit subsequently entered into amendments to the Pilot Line of Credit on May 9, 2019 and May 10, 2019. The parties entered into Amendment No. 1 to the Pilot Line of Credit effective September 3, 2019 (the “Amended Pilot Line of Credit”). The Amended Pilot Line of Credit was fully executed by all parties on September 9, 2019. The Amended Pilot Line of Credit provided for, among other things:

●

a $0.2 million increase in the aggregate principal amount available under the line of credit (from $12.8 million to $13.0 million); and

●

Pre-payment by NPS to Pilot in a principal amount equal to the amount set forth opposite such date below, together with accrued and unpaid interest thereon:

Date	Principal Amount
September 30, 2019	$0.1 million
October 31, 2019	$0.1 million

As of the filing date of this Quarterly Report, the September and October payments referenced above had been made.

26

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

	September 30,	December 31,
	2019	2018
	(in thousands)
Amended Pilot Line of Credit	$12,689	$-
Less: Unamortized debt issue costs	(407)	-
Less: Interest payable, short-term	(102)	-
	$12,180	$-

Key terms of the Amended Pilot Line of Credit are as follow:

Principal Amount:	Up to $13.0 million
Maturity Date:	May 2020
Monthly Payment:	$0.1 million (September and October 2019 only)
Interest Payment:	$0.2 million monthly
Interest Rate:	12.00% per annum

The Amended Pilot Line of Credit was primarily used to fund the Settlement Payment to GEL. Remaining funds are being used to finance NPS' purchase of crude oil from Pilot pursuant to certain purchase and supply contracts and to provide working capital. The Amended Pilot Line of Credit contains customary affirmative and negative covenants and events of default and is secured by (i) NPS receivables, (ii) NPS assets, including a tank lease (the “Tank Lease”), and (iii) LRM receivables. On May 3, 2019, as an inducement to Pilot’s entry into the Pilot Line of Credit, Blue Dolphin and Pilot entered into a Pledge Agreement (the “Pledge Agreement”) whereby Blue Dolphin pledged its equity interests in NPS to Pilot to secure NPS’ obligations under the Pilot Line of Credit. Blue Dolphin, LE, LRM, and LEH have each guaranteed NPS’ obligations under the Pilot Line of Credit. On May 10, 2019, LE, NPS, Pilot and Veritex entered into a Subordination and Attornment Agreement (the “Subordination Agreement”), providing that, if Veritex in its capacity as a secured lender of LE and LRM were to foreclose on LE property that NPS was leasing from LE pursuant to the Tank Lease, Veritex would permit the continued performance of obligations under the Tank Lease so long as certain conditions are met. The effectiveness of the Subordination Agreement is subject to certain conditions, including the agreement and concurrence of the USDA.

(13) 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, and we depreciated the amount added to property and equipment and recognized accretion expense relating to the discounted liability over the remaining life of the asset. At December 31, 2018, the liability was fully accreted.

27

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

Due to the length of inactivity of our pipelines and facilities assets, BDPL is required by the Bureau of Ocean Energy Management (“BOEM”) to abandon-in-place certain pipelines and remove an anchor platform in federal waters. Members of management met with BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) on August 15, 2019. BSEE mandated BDPL to submit permit applications for pipeline and platform decommissioning within six (6) months (no later than February 15, 2020), and to develop and implement a safe boarding plan for submission with such permit applications. Further, BDPL must conduct approved, permitted work within 12 months (no later than August 15, 2020).  If these actions are not addressed within the allowable timeframes, BOEM indicated that BDPL will be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct INCs, civil penalties, and revocation of BDPL’s operator designation. As of the filing date of this Quarterly Report, BDPL engaged a third-party consultant to oversee the abandonment project, and the consultant is preparing the permit applications for submittal to BSEE. If BDPL is unable to comply within BSEE’s designated timetables and is assessed significant penalties by BSEE, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. Plugging and abandonment costs will be 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,
	2019	2018
	(in thousands)
Asset retirement obligations, at the beginning of the period	$2,580	$2,315
Accretion expense	-	265
	2,580	2,580
Less: asset retirement obligations, current portion	(2,580)	(2,580)
Long-term asset retirement obligations, at the end of the period	$-	$-

(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, 2019 and December 31, 2018, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $0.4 million and $1.2 million, respectively.

Key Supplier. Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We have a long-term crude supply contract in place with Pilot. In connection with the crude supply contract, Pilot stores its crude oil at the Nixon Facility pursuant to a terminal services agreement. Pilot currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect Pilot to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected by net losses, working capital deficits, and financial covenant defaults in secured loan agreements.(See  “Note (19) Subsquent Event” for additional disclosures related to the crude supply contract.)

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, 2019, we had 4 customers that accounted for approximately 98% of our refined petroleum product sales. LEH, a related party, was 1 of these 4 significant customers and accounted for approximately 32% of our refined petroleum product sales.  At September 30, 2019, these 4 customers represented approximately $0.6 million in accounts receivable.  LEH represented approximately $0.3 million in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related-Party Transactions,” “Note (11) Long-Term Debt and Accrued Interest,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

28

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

For the nine months ended September 30, 2019, we had 4 customers that accounted for approximately 98% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 31% of our refined petroleum product sales.  At September 30, 2019, these 4 customers represented approximately $0.6 million in accounts receivable.  LEH represented approximately $0.3 million in accounts receivable.

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.

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.

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,
	2019		2018		2019		2018
	(in thousands, except percent amounts)
LPG mix	$8	0.0%	$-	0.0%	$17	0.0%	$3	0.0%
Naphtha	14,147	18.2%	24,127	25.5%	43,358	19.5%	64,093	25.2%
Jet fuel	25,035	32.3%	27,299	28.9%	70,017	31.4%	73,415	28.9%
HOBM	17,044	22.0%	21,735	23.0%	49,951	22.5%	60,594	23.8%
AGO	21,303	27.5%	21,307	22.6%	59,309	26.6%	56,140	22.1%
	$77,537	100.0%	$94,468	100.0%	$222,652	100.0%	$254,245	100.0%

(15) Leases

We adopted the new lease accounting guidance using the modified retrospective method and applied it to all leases based on the contract terms in effect as of January 1, 2019. For existing contracts, we carried forward our historical assessment of: (i) whether contracts are or contain leases, (ii) lease classification, and (iii) initial direct costs.

As of September 30, 2019, leases were as follow:

●

Office Lease (Operating Lease). BDSC has an office lease related to our principal office space in Houston, Texas. The 68-month operating lease expires in 2023. BDSC has the option to extend the lease term for one additional five (5) year period if notice of intent to extend is provided to the lessor at least twelve (12) months before the end of the current term. LEH subleases a portion of this leased office space (see “Note (9) Related-Party Transactions” related to the LEH office sub-lease agreement).  Sublease income received from LEH totaled $0.01 million for both three-month periods ended September 30, 2019 and 2018. Sublease income received from LEH totaled $0.03 million for both nine-month periods ended September 30, 2019 and 2018.

●

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

●

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

29

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

For leases with terms greater than 12 months, including renewal options when appropriate, we record the related right-of-use asset and lease liability as the present value of the fixed lease payments over the lease term. Since the leases do not provide a readily-determinable discount rate, we use the incremental borrowing rate to discount lease payments to present value. The following table presents the lease-related assets and liabilities recorded on the consolidated balance sheet:

	Classification on	Septeber 30,
	Consolidated Balance Sheet	2019
		(in thousands)
Assets
Operating lease right-of-use assets	Operating lease right-of-use assets	$787
Less: Accumulated amortization on operating lease assets	Operating lease right-of-use assets	(102)
		685
Finance lease assets	Property and equipment, net	180
Less: Accumulated amortization on finance lease assets	Property and equipment, net	(26)
		154
Total lease assets		$839
Liabilities
Current
Operating lease	Current portion of lease liabilities	$172
Finance leases	Current portion of lease liabilities	90
		262
Noncurrent
Operating lease	Long-term lease liabilities, net of current	610
Total lease liabilities		$872

Weighted average remaining lease term in years
Operating lease	3.92
Finance leases	0.59
Weighted average discount rate
Operating lease	8.25%
Finance leases	8.25%

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

	Three Months Ended	Nine Months Ended
	September 30,	September 30,
	2019	2019
	(in thousands)
Operating lease costs	$51	$154
Finance lease costs:
Depreciation of leased assets	4	12
Interest on lease liabilities	2	4
Total lease cost	$57	$170

30

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

	Three Months Ended	Nine Months Ended
	September 30,	September 30,
	2019	2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating lease	$40	$81
Operating cash flows for finance leases	2	4
Financing cash flows for finance leases	13	35

As of September 30, 2019, maturities of lease liabilities for the periods indicated were as follows:

	Operating Lease	Financing Leases	Total
	(in thousands)
2020	$172	$17	$189
2021	189	73	262
2022	209	-	209
2023	212	-	212
	$782	$90	$872

As of September 30, 2019, our future minimum annual lease commitments that are non-cancelable for the periods indicated are as follow:

	Operating
	Lease
2020	$230
2021	233
2022	236
2023	219
	$918

31

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

(16) Income Taxes

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
	(in thousands)
Current
Federal	$-	$-	$-	$108
State	-	-	-	-
Deferred
Change in valuation allowance	-	-	-	109
Total provision for income taxes	$-	$-	$-	$217

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.

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

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

	September 30,	December 31,
	2019	2018
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$12,618	$11,260
Accrued arbitration award payable	-	2,850
Business interest expense	1,695	704
Start-up costs (crude oil and condensate processing facility)	615	678
Asset retirement obligations liability/deferred revenue	541	542
AMT credit and other	50	108
Total deferred tax assets	15,519	16,142
Deferred tax liabilities:
Basis differences in property and equipment	(5,767)	(5,153)
Total deferred tax liabilities	(5,767)	(5,153)
	9,752	10,989
Valuation allowance	(9,702)	(10,881)
Deferred tax assets, net	$50	$108

32

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

NOL Carryforwards. Under IRC Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than fifty (50) percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, relating to a series of private placements, and in 2012, because of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income. In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of approximately $0.6 million per year. Unused portions of the annual use limitation amount may be used in subsequent years. Because of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused. NOL carryforwards that were generated after the 2012 ownership change and prior to 2018 are not subject to an annual use limitation under IRC Section 382 and may be used for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change. NOL carryforwards that were generated after 2017 may only be used to offset 80% of taxable income and are carried forward indefinitely.

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

	Net Operating Loss Carryforward
	Pre-Ownership Change	Post-Ownership Change	Total
	(in thousands)
Balance at December 31, 2017	$9,614	$30,219	$39,833
Net operating losses	-	7,116	7,116
Balance at December 31, 2018	$9,614	$37,335	$46,949
Net operating losses	-	6,460	6,460
Balance at September 30, 2019	$9,614	$43,795	$53,409

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, 2019 and December 31, 2018, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2019 and December 31, 2018.

33

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

(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,
	2019	2018	2019	2018
	(in thousands, except share and per share amounts)
Net income (loss)	$8,167	$(937)	$5,615	$748
Basic and diluted income (loss) per share	$0.74	$(0.09)	$0.51	$0.07
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,975,514	10,925,513	10,975,514	10,925,513

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 three and nine months ended September 30, 2019 and 2018 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

(18) Commitments and Contingencies

Legal Matters.

Final Arbitration Award and Settlement Agreement. As previously disclosed, LE was involved in the GEL Arbitration with GEL, an affiliate of Genesis, related to a contractual dispute involving the Crude Supply Agreement and Joint Marketing Agreement, each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered 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 $31.3 million.

In July 2018, the Lazarus Parties and GEL entered into the Settlement Agreement. The Settlement Agreement was subsequently amended five times to extend the Settlement Payment Date and/or modify certain terms related to the Interim Payments or the Settlement Payment. During the period September 2017 to August 2019, GEL received the following amounts from the Lazarus Parties to reduce the outstanding balance of the Final Arbitration Award:

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

The Lazarus Parties made all payments to GEL as required for the Settlement to be final and effective. As a result: (i) the Settlement occurred on August 23, 2019, (ii) the mutual releases became effective, (iii) GEL filed a stipulation of dismissal of claims against LE, and (iv) Blue Dolphin recognized a $9.1 million gain on the extinguishment of debt on its consolidated statements of operations for the three and nine months ended September 30, 2019. Until the Settlement occurred, the debt was reflected on Blue Dolphin’s consolidated balance sheets as accrued arbitration award payable. At September 30, 2019 and December 31, 2018, accrued arbitration award payable was $0 and $21.1million, respectively.

34

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

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

Other Legal Matters. We are involved in lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens, contract-related disputes, administrative proceedings, and financial assurance (bonding) requirements with regulatory bodies. Management is in discussion with all concerned parties and does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows. However, there can be no assurance that such discussions will result in a manageable outcome or that we will be able to meet financial assurance (bonding) requirements. If Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

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

Financing Agreements. See “Note (11) Long-Term Debt and Accrued Interest” and “Note (12) Line of Credit Payable” for additional disclosures related to financing agreements.

Guarantees. LEH and Jonathan Carroll 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 and Accrued Interest” for additional disclosures related to guarantees.

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

Nixon Facility Expansion. Wehave made and 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 a petroleum storage tank.

Supplemental Pipeline Bonds. In a letter dated March 30, 2018, BOEM ordered BDPL to provide additional supplemental bonds or acceptable financial assurance of approximately $4.8 million (the “Separate Orders”) within sixty (60) calendar days of receipt of the letter. The Separate Orders relate to five (5) existing pipeline rights-of-way. BOEM issued an Incident of Noncompliance (“INC”) for each Separate Order dated June 8, 2018 (the “June 2018 INCs”) and received by BDPL on June 11, 2018. BOEM asserts that the June 2018 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 June 2018 INCs on August 8, 2018. The Interior Board of Land Appeals (the “IBLA”) granted multiple extension requests that extended BDPL’s deadline for filing a Statement of Reasons. On August 9, 2019, BDPL timely filed its Statement of Reasons with the IBLA. On October 16, 2019, BOEM filed a motion requesting a 30-day extension to file its answer to BDPL’s Statement of Reasons. BOEM filed its answer to BDPL’s Statement of Reasons, requesting that the IBLA affirm the June 2018 INCs. In light of BDPL’s August 2018 meeting with BSEE, BDPL intends to request a stay in the IBLA matter until August 2020. The Office of the Solicitor of the U.S. Department of the Interior (the “Solicitor's Office”) was agreeable to a 10-day extension while it conferred with BOEM on BDPL’s stay request. On October 31, 2019, BDPL filed a motion to request the 10-day extension, which motion was subsequently granted by the IBLA. The Solicitor's Office consented to an additional 14-day extension, until November 22, 2019, for BDPL to file its reply. On November 8, 2019, BDPL filed a motion to request the 14-day extension.

BDPL’s pending appeal of the June 2018 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. Members of management met with BOEM and BSEE on August 15, 2019. Based upon discussions with BOEM, BDPL reasonably expects that its pipeline and platform decommissioning obligations, including incremental amounts of supplemental bonds, can be significantly reduced or eliminated, which may serve to partially or fully resolve the Separate Orders and the June 2018 INCs (see “Idle Iron” discussion below). As of September 30, 2019 and December 31, 2018, 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 additional financial assurance or is assessed significant penalties under the June 2018 INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. At this time, we are unable to predict the outcome of the Separate Orders. Accordingly, we have not recorded a liability on our consolidated balance sheet as of September 30, 2019.

35

BLUE DOLPHIN ENERGY COMPANY	FORM 10-Q 9/30/19
Notes to Consolidated Financial Statements (Continued)

Idle Iron. BSEE requires operators to decommission certain wells and platforms that have not been used in the past five (5) years for exploration and development operations or as infrastructure to support such operations. BDPL’s Blue Dolphin Pipeline has been inactive since September 2012. Due to the length of inactivity, BSEE required BDPL to: (i) flush and fill the Blue Dolphin Pipeline, (ii) abandon-in-place a portion of the Blue Dolphin Pipeline’s 20” segment and certain smaller diameter connecting lateral lines that reside offshore in federal waters and (iii) remove from federal waters the GA-288C anchor platform. In April 2016, BDPL submitted decommissioning permit applications to BSEE for three (3) pipeline segments – Segments #13101, #9428, and #15635 – and the GA-288C anchor platform. In June 2016, BDPL also submitted a decommissioning permit application to the U.S. Army Corps of Engineers (“USCOE”) for abandonment of Segment #9428. The permit applications were granted by BSEE at varying dates between August 2016 and April 2017. Work must typically be completed within 120 days from the date of permit approval. The USCOE withdrew BDPL’s decommissioning permit application in April 2018.

In a letter dated December 19, 2018, BSEE issued to BDPL an INC for its failure to flush and fill Segment #13101 (the “December 2018 INC”) pursuant to the pipeline decommissioning approval letter issued in March 2017. Members of management met with BOEM and BSEE on August 15, 2019. BSEE proposed that BDPL submit permit applications for pipeline and platform decommissioning within six (6) months (no later than February 15, 2020), and to develop and implement a safe boarding plan for submission with such permit applications. Further, BSEE proposed that BDPL would need to conduct approved, permitted work in a safe manner within 12 months (no later than August 15, 2020).  If these actions are not addressed within the allowable timeframes, BOEM indicated that BDPL would be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct INCs, civil penalties, and revocation of BDPL’s operator designation. As of the filing date of this Quarterly Report, BDPL engaged a third-party consultant to oversee the abandonment project, and the consultant is preparing the permit applications for submittal to BSEE. If BDPL is unable to comply within BSEE’s designated timetables and is assessed significant penalties by BSEE, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. As of September 30, 2019, BDPL maintained $2.6 million in asset retirement obligations related to abandonment of these assets.

(19) Subsequent Event

On November 11, 2019, LE entered into a long-term crude supply contract with Pilot. The crude supply contract has a volume-based, initial term of approximately 24.8 million bbls, after which time the contract renews on a 1-year evergreen basis until either party terminates the contract. Pilot may terminate the contract by giving LE sixty (60) days prior written notice at any time during the term of the contract. LE may terminate the contract upon expiration of the initial term or at any time during a renewal term by giving Pilot sixty (60) days prior written notice. As consideration for LE entering into the crude supply contract for an extended term, Pilot paid LE a one-time payment of $2.5 million.

Remainder of Page Intentionally Left Blank

36

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

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, 2019 (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 Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2019 and June 30, 2019, as well as our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “Annual Report”).  

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 and this Quarterly Report:

Risks Related to Our Business and Industry

●

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

●

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

●

Our substantial debt in the current portion of long-term debt, which is currently in default, could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

●

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

●

LEH holds a significant interest in us, and related-party transactions with LEH and its affiliates may cause conflicts of interest that may adversely affect us.

●

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

●

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

●

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

●

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

●

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

●

Our insurance policies may be inadequate or expensive.

37

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

●

Our ability to use net operating loss (“NOL”) carryforwards to offset future taxable income for U.S. federal income tax purposes is 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 Operations

●

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

●

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

●

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

●

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

●

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

●

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate. Further, LEH and its affiliates (including Jonathan Carroll) may, but are not required to, fund our working capital requirements in the event our internally generated cash flows and other sources of liquidity are inadequate.

●

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

●

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

●

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

●

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

●

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

●

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

●

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

Risks Related to Our Pipelines and Oil and Gas Properties

●

Assessment of civil penalties by BOEM for failure to satisfy orders to increase supplemental pipeline bonds could significantly impact our operations, liquidity, and financial condition.

●

Assessment of civil penalties by BSEE for failure to decommission platform and pipeline assets within a prescribed time period could significantly impact our operations, liquidity, and financial condition.

●

More stringent requirements imposed by BOEM and BSEE related to the decommissioning, plugging, and abandonment of wells, platforms, and pipelines could materially increase our estimate of 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.

38

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

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.

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 in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and more than 1.0 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 dollar per bbl price difference between crude oil and condensate (input) and refined petroleum products (output), is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. Our per bbl cost to acquire crude oil and condensate and the dollar per bbl price for which our refined petroleum products are ultimately sold depend on the economics of supply and demand. Supply and demand are affected by numerous factors, most, if not all, of which are beyond our control, including:

●

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.

39

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Refinery Downtime

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

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

Tolling and Terminaling Operations

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

●

price (in terms of storage fees);

●

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 parties to a variety of agreements with LEH and its affiliates and a counter-party. Related-party agreements with LEH include: (i) an Amended and Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL, (iv) an Amended and Restated Promissory Note with Blue Dolphin, and (v) an office sub-lease agreement with BDSC. In addition, we currently rely on advances from LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. There can be no assurances that LEH and its affiliates will continue to fund our working capital requirements. (See “Part 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 refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We have a long-term crude supply contract in place with Pilot Travel Centers LLC ("Pilot"). In connection with the crude supply contract, Pilot stores its crude oil at the Nixon Facility pursuant to a terminal services agreement. Pilot currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect Pilot to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected by net losses, working capital deficits, and financial covenant defaults in secured loan agreements. (See “Part I, Item 1. Financial Statements - Note (19) Subsequent Event” for additional disclosures related to the crude supply contract.)

Management believes that it is taking the appropriate steps to improve our operations and financial stability. If our business strategy is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under the existing contract or otherwise.

40

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Results of Operations

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

Consolidated Results

Three Months Ended September 30, 2019 (the “Current Quarter”) Compared to September 30, 2018 (the “Prior Quarter”).

Total Revenue from Operations. For the Current Quarter, we had total revenue from operations of $78.6 million compared to total revenue from operations of $95.5 million for the Prior Quarter, a decrease of nearly 18%. Approximately 99% of our revenue is derived from refinery operations while 1% is derived from tolling and terminaling. Refinery operations revenue decreased approximately $16.9 million in the Current Quarter compared to the Prior Quarter. The decrease in refinery operations revenue was due to lower commodity pricing per bbl on refined petroleum products sold and slightly lower sales volume in the Current Quarter compared to the Prior Quarter. Tolling and terminaling revenue was relatively flat at $1.0 million for both the Current Quarter and the Prior Quarter.

Total Cost of Goods Sold. Total cost of goods sold was $76.2 million for the Current Quarter compared to $94.1 million for the Prior Quarter. The 19% decrease in total cost of goods sold in the Current Quarter compared to the Prior Quarter related to lower commodity prices per bbl for crude oil and chemicals and slightly decreased throughput volume.

Gross Profit (Loss) / Gross Margin (Deficit). For the Current Quarter, we had a gross profit of $2.4 million, or a gross margin of approximately 3%, compared to gross profit of $1.4 million, or a gross margin of nearly 2%, for the Prior Quarter. The $1.0 million increase in gross profit between the periods primarily related to higher margins on slightly lower volume in the Current Quarter compared to the Prior Quarter.

LEH Operating Fee. The LEH operating fee under the Amended and Restated Operating Agreement was relatively flat at $0.1 million in the Current Quarter compared to $0.1 million in the Prior Quarter. (See “Part I, Item 1. Financial Statements – Note (9) Related-Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.)

General and Administrative Expenses. General and administrative expenses totaled $0.7 million in the Current Quarter compared to $0.9 million in the Prior Quarter, a decrease of approximately 30%. The decrease between the periods was primarily due to lower legal expenses related to the GEL matter.

Depreciation and Amortization. We recorded depreciation and amortization expenses of $0.6 million in the Current Quarter compared to $0.5 million in the Prior Quarter, an increase of 32%. The increase related to placement in service of a new boiler and new petroleum storage tanks.

Other Income (Expense). Total other income was $7.2 million in the Current Quarter compared to an expense of $0.7 million in the Prior Quarter. Total other income in the Current Quarter was the result of a $9.1 million gain on the extinguishment of debt related to the GEL Settlement. Interest and other expense totaled $1.9 million in the Current Quarter compared to $0.8 million in the Prior Quarter. The significant increase primarily related to the addition of a line of credit with Pilot and secured loans with Veritex Community Bank (“Veritex”) no longer being capitalized in the Current Quarter compared to the Prior Quarter.

Net Income (Loss). For the Current Quarter, we reported net income of $8.2 million, or income of $0.74 per share, compared to a net loss of $0.9 million, or a loss of $0.09 per share, for the Prior Quarter. The significant increase between the periods was the result of a gain on the extinguishment of debt related to the GEL Settlement. Excluding the gain on extinguishment of debt, we would have reported a net loss of $1.0 million, or a loss of $0.09 per share, for the Current Quarter. Net loss for the Prior Quarter was primarily the result of lower and sometimes negative margins per bbl on refined petroleum products.

41

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Nine Months Ended September 30, 2019 (the “Current Nine Months”) Compared to September 30, 2018 (the “Prior Nine Months”).

Total Revenue from Operations. For the Current Nine Months, we had total revenue from operations of $225.9 million compared to total revenue from operations of $256.9 million for the Prior Nine Months, a decrease of 12%. Approximately 99% of our revenue is derived from refinery operations while 1% is derived from tolling and terminaling. Refinery operations revenue decreased approximately $31.6 million in the Current Nine Months compared to the Prior Nine Months. The decrease in refinery operations revenue was due to lower commodity pricing per bbl on refined petroleum products sold and slightly lower sales volume in the Current Nine Months compared to the Prior Nine Months. For the same period, tolling and terminaling revenue increased approximately $0.6 million, or approximately 22%, as a result of increased storage fees under new and renewed customer agreements.

Total Cost of Goods Sold. Total cost of goods sold was $220.3 million for the Current Nine Months compared to $249.7 million for the Prior Nine Months. The nearly 12% decrease in total cost of goods sold in the Current Nine Months compared to the Prior Nine Months related to lower commodity prices per bbl for crude oil and chemicals and slightly decreased throughput volume.

Gross Profit / Gross Margin. For the Current Nine Months, gross profit totaled $5.6 million, or gross margin of nearly 3%, compared to gross profit of $7.2 million, or gross margin of nearly 3%, for the Prior Nine Months. The decrease in gross profit between the periods primarily related to lower margins on slightly less volume in the Current Nine Months compared to the Prior Nine Months.

LEH Operating Fee. The LEH operating fee under the Amended and Restated Operating Agreement was relatively flat at $0.5 million in the Current Nine Months compared to the Prior Nine Months. (See “Part I, Item 1. Financial Statements – Note (9) Related-Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.)

General and Administrative Expenses. General and administrative expenses totaled $1.9 million in the Current Nine Months compared to $2.3 million in the Prior Nine Months, a decrease of 16%. The decrease between the periods was primarily due to lower legal expenses related to the GEL matter.

Depreciation and Amortization. We recorded depreciation and amortization expenses of $1.9 million in the Current Nine Months compared to $1.4 million in the Prior Nine Months, an increase of nearly 33%. The increase related to placement in service of a new boiler and new petroleum storage tanks.

Other Income (Expense). Total other income was $4.4 million in the Current Nine Months compared to an expense of $2.2 million in the Prior Nine Months. Total other income in the Current Nine Months was the result of a $9.1 million gain on the extinguishment of debt related to the GEL Settlement. Interest and other expense totaled $4.7 million in the Current Nine Months compared to $2.3 million in the Prior Quarter. The significant increase primarily related to the addition of a line of credit with Pilot and secured loans with Veritex no longer being capitalized in the Current Nine Months compared to the Prior Nine Months.

Income Tax Benefit. We recognized an income tax benefit of $0 in the Current Nine Months compared to $0.3 million in the Prior Nine Months. Income tax benefit in the Prior Nine Months related to a refundable Alternative Minimum Tax credit. (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 Months, we reported net income of $5.6 million, or income of $0.51 per share, compared to net income of $0.7 million, or income of $0.07 per share, for the Prior Nine Months. The significant increase between the periods was the result of a gain on the extinguishment of debt related to the GEL Settlement. Excluding the gain on the extinguishment of debt, we would have reported a net loss of $3.5 million, or a loss of $0.32 per share, for the Current Nine Months. The gain on the extinguishment of debt and slightly increased tank rental revenue offset less favorable margins per bbl and slightly lower sales throughput volume in the Current Nine Months compared to the Prior Nine Months.

42

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Non-GAAP Financial Measures

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

Refining Gross Profit per Bbl – For the Current Quarter, we had a refining gross profit of $1.11 per bbl compared to a refining gross profit of $0.29 per bbl for the Prior Quarter, reflecting an increase of $0.82 per bbl. The significant increase between the periods primarily related to higher margins due to market fluctuations in the Current Quarter compared to the Prior Quarter. (See “Glossary of Selected Energy and Financial Terms” in this Quarterly Report for the definition of gross margin per bbl.)

For the Current Nine Months, we had refining gross profit of $0.71 per bbl compared to a refining gross profit of $1.37 per bbl for the Prior Nine Months, reflecting a decrease of $0.66 per bbl. The significant decrease between the periods primarily related to lower margins due to market fluctuations in the Current Nine Months compared to the Prior Nine Months.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
	(in thousands except per bbl amounts)
Refinery operations revenue	$77,537	$94,468	$222,652	$254,245
Less: Total cost of goods sold	(76,229)	(94,126)	(220,301)	(249,708)
	1,308	342	2,351	4,537
Sales (Bbls)	1,181	1,192	3,314	3,324
Gross Margin per Bbl	$1.11	$0.29	$0.71	$1.37

Remainder of Page Intentionally Left Blank

43

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

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,
	2019	2018	2019	2018
Calendar Days	92	92	273	273
Refinery downtime	(2)	(3)	(20)	(24)
Operating Days	90	89	253	249
Total refinery throughput (bbls)	1,198,102	1,220,259	3,379,266	3,411,193
Operating days:
bpd	13,312	13,711	13,357	13,700
Capacity utilization rate	88.7%	91.4%	89.0%	91.3%
Calendar days:
bpd	13,023	13,264	12,378	12,495
Capacity utilization rate	86.8%	88.4%	82.5%	83.3%
Total refinery production (bbls)	1,169,745	1,184,348	3,294,914	3,313,682
Operating days:
bpd	12,997	13,307	13,023	13,308
Capacity utilization rate	86.6%	88.7%	86.8%	88.7%
Calendar days:
bpd	12,715	12,873	12,069	12,138
Capacity utilization rate	84.8%	85.8%	80.5%	80.9%

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.

For the Current Quarter, total refinery throughput bbls and total refinery production bbls were down slightly compared to the Prior Quarter as a result of a crude heater issue. Management plans to address the crude heater issue during the next refinery turnaround. During the Current Quarter, the refinery experienced 2 days of downtime primarily related to equipment repairs. During the Prior Quarter, the refinery experienced 3 days of downtime primarily related to maintenance and equipment repairs.

For the Current Nine Months compared to the Prior Nine Months, total refinery throughput bbls and total refinery production bbls were also down slightly as a result of the crude heater noted above. During the Current Nine Months, the refinery experienced 20 days of downtime primarily related to a maintenance turnaround and equipment repairs. During the Prior Nine Months, the refinery experienced 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.

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 9/30/19

Liquidity and Capital Resources

Overview.

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 quarterly net losses, inadequate working capital, and defaults under secured loan agreements. However, management has made significant progress towards improving operations and financial stability. Over the past 2 years, a significant portion of our cash from operations was dedicated to reducing the outstanding balance of the Final Arbitration Award. During the Current Quarter, the Lazarus Parties successfully made the final payment related to the Final Arbitration Award and the Settlement between GEL and the Lazarus Parties became final and effective. See “Part I, Item 1. Financial Statements – Note (1) Organization –Going Concern” for additional disclosures related to defaults under secured loan agreements and going concern. See “Part I., Item 1. Financial Statements – Note (18) Commitments and Contingencies –Final Arbitration Award and Settlement Agreement” for additional disclosures related to the Final Arbitration Award and the Settlement Agreement with GEL.

Our results of operations and liquidity are highly dependent upon the margins that we receive for our refined petroleum products. The dollar per bbl price difference between crude oil and condensate (input) and refined petroleum products (output), is the most significant driver of refining margins, and they have historically been subject to wide fluctuations. There can be no assurance that margins for refined petroleum products will be favorable, LEH and its affiliates will continue to fund our working capital needs in periods of working capital deficits, or we will be able to obtain additional financing on commercially reasonable terms or at all.

Cash Flow.

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

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
	(in thousands)
Beginning cash, cash equivalents, and restricted cash	$1,967	$2,012	$1,665	$2,146
Cash flow from operations
Adjusted profit (loss) from operations	362	(366)	(778)	2,229
Change in assets and current liabilities	408	400	(9,746)	(1,075)
Total cash flow from operations	770	34	(10,524)	1,154
Cash inflows (outflows)
Proceeds from issuance of debt	-	-	12,402	-
Payments on debt	(771)	224	(1,312)	(723)
Net activity on related-party debt	(178)	472	(407)	924
Capital expenditures	(964)	(595)	(1,458)	(1,826)
Total cash inflows (outflows)	(1,557)	101	10,039	(1,625)
Total change in cash flows	(787)	135	(485)	(471)
Ending cash, cash equivalents, and restricted cash	$1,180	$2,147	$1,180	$1,675

For the Current Quarter, we had cash flow from operations of $0.8 million compared to cash flow from operations of $0.03 million for the Prior Quarter. The approximate $0.8 million increase in cash flow from operations between the periods related to paying out less in cash payments toward the accrued arbitration award during the Current Quarter than in the Prior Quarter.

45

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

For the Current Nine Months, we had a cash flow deficit of $10.5 million compared to cash flow from operations of $1.2 million for the Prior Nine Months. The $9.3 million decrease in cash flow from operations between the periods was primarily the result of cash payments toward the accrued arbitration award, which included a $10.0 million settlement payment to GEL. We had proceeds from the issuance of debt of $12.4 million in the Current Nine Months compared to $0 in the Prior Nine Months. Proceeds from the issuance of debt, which related to a line of credit with Pilot, were used primarily to fund the settlement payment to GEL. See “Part I, Item 1. Note (12) Line of Credit Payable” for additional disclosures related to debt agreement with Pilot.

Working Capital.

We had a working capital deficit of $64.9 million and $71.9 million at September 30, 2019 and December 31, 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $22.9 million and $30.0 at September 30, 2019 at December 31, 2018, respectively.

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.

Crude Oil and Condensate Supply.

We have a long-term crude supply contract in place with Pilot. In connection with the crude supply contract, Pilot stores its crude oil at the Nixon Facility pursuant to a terminal services agreement. Pilot currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect Pilot to continue to do so for the foreseeable future. Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, and our ability to purchase adequate amounts of crude oil and condensate could be adversely affected by net losses, working capital deficits, and financial covenant defaults in secured loan agreements. (See “Part I, Item 1. Financial Statements - Note (19) Subsequent Event” for additional disclosures related to the crude supply contract.)

Capital Spending.

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

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

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

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

46

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Contractual Obligations and Debt Agreements.

See the following notes under “Part I, Item 1. Financial Statements” regarding:

●

GEL. “Note (18) Commitments and Contingencies– Final Arbitration Award and Settlement Agreement” for disclosures related to the Final Arbitration Award to GEL and Settlement Agreement with GEL.

●

Related-Party. “Note (9) Related-Party Transactions” for a summary of the agreements we have in place with related parties.

●

Long-Term Debt. “Note (11) Long-Term Debt and Accrued Interest” for a summary of our long-term debt.

●

Short-Term Debt. “Note (13) Line of Credit Payable” for a summary of our short-term debt.

●

Operating and Finance Leases. “Note (15) Leases” for disclosures related to our operating and finance leases.

●

Supplemental Pipeline Bonds and Abandonment Requirements. “Note (18) Commitments and Contingencies – Supplemental Pipeline Bonds” and “— Idle Iron” for a discussion of supplemental pipeline bonding and offshore pipeline and platform abandonment requirements.

Indebtedness.

The principal balances outstanding plus accrued interest on our debt (including related-party) for the periods indicated were as follow:

	September 30,	December 31,
	2019	2018
	(in thousands)
First Term Loan Due 2034 (in default)	$22,178	$22,593
Amended Pilot Line of Credit	12,689	-
Second Term Loan Due 2034 (in default)	9,197	9,353
Notre Dame Debt (in default)	8,418	7,821
BDPL Loan Agreement (in default)	6,014	5,534
March Carroll Note (in default)	1,705	1,147
March Ingleside Note (in default)	1,345	1,283
June LEH Note (in default)	868	611
Capital lease	-	41
	$62,414	$48,383
Less: Current portion of long-term debt	(54,249)	(41,904)
Less: Unamortized debt issue costs	(2,317)	(2,006)
Less: Accrued interest payable and accrued interest payable,
related party	(5,848)	(4,473)

Principal payments on long-term debt totaled $0.8 million in the Current Quarter compared to $0.2 million in the Prior Quarter. Principal payments on long-term debt totaled $1.3 million in the Current Nine Months compared to $0.7 million in the Prior Nine Months. As of the filing date of this Quarterly Report, LE and LRM were current on monthly payments under the First Term Loan Due 2034 and Second Term Loan Due 2034, as well as interest payments on the Amended Pilot Line of Credit. To date, there have been no payments under the Notre Dame Debt and the BDPL Loan Agreement.

47

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

As previously disclosed, the Lazarus Parties were prohibited by GEL from making payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements (see also “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies – Legal Matters – Final Arbitration Award and Settlement Agreement”). Now that the Settlement between GEL and the Lazarus Parties is final and effective, management has resumed payments of the common stock component to Mr. Carroll under the agreements. On November 14, 2019, Mr. Carroll received 1,351,851 shares of Common Stock, which represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019. Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. Currently, management does not intend on paying Mr. Carroll the cash portion due to Blue Dolphin’s working capital deficits. The cash portion of guaranty fees owed to Mr. Carroll will continue to be accrued and added to the principal balance of the March Carroll Note. See “Part I, Item 1. Financial Statements – Note (9) Related-Party Transactions – Financial Agreements – March Carroll Note” and “ – Amended and Restated Guaranty Fee Agreements” for additional disclosures related to payments to Jonathan Carroll.

As described elsewhere in this Quarterly Report, Veritex notified obligors that the Final Arbitration Award constituted 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, 2019, 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 did not accelerate or call due the secured loan agreements considering the Settlement Agreement. Instead, 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 agreementsVeritex worked with LE and LRM and was aware and party to all discussions and arrangements with GEL surrounding the Settlement Agreement, all amendments, and the final and effective Settlement with GEL. In a notice to obligors dated April 30, 2019 (the "Veritex Consent'), Veritex agreed to waive certain covenant defaults and forbear from enforcing its remedies under the secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of a payment reserve account in the amount of $1.0 million as required by one of the secured loan agreements on or before August 31, 2019. As of the filing date of this Quarterly Report, the payment reserve account had not been fully replenished. Any exercise by Veritex of its rights and remedies under such secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

We adopted new ASU guidance related to leases. As a result, disclosures previously reported as indebtedness within this “Liquidity and Capital Resources” section as capital leases are now excluded. Amounts are now reported as finance leases within “Part I, Item. – Note (15) Leases.” See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – New Pronouncements Adopted” for information related to the new lease accounting standard.

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

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

Off-Balance Sheet Arrangements

None.

48

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Critical Accounting Policies

Long-Lived Assets. See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – Property and Equipment”.

Revenue Recognition. See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – Revenue Recognition”.

Inventory. See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – Inventory”.

Asset Retirement Obligations. See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – Asset Retirement Obligations,” “— Note (13) Asset Retirement Obligations,” and “— Note (18) Commitments and Contingencies – Idle Iron”.

Income Taxes. See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – Income Taxes” and “– Note (16) Income Taxes”.

Recently Adopted Accounting Guidance

See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – New Pronouncements Adopted”.

New Pronouncements Issued, Not Yet Effective

See “Part I, Item 1. Financial Statements – Note (3) Significant Accounting Policies – New Pronouncements Issued, Not Yet Effective”.

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 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 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.

49

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

Changes in Internal Control over Financial Reporting

In connection with the adoption on January 1, 2019 of new accounting guidance for leases, we implemented new processes and internal controls related to our leases.

Except as described above, 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 months ended September 30, 2019 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.)

PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Final Arbitration Award

See “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies – 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

We are involved in lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens, contract-related disputes, administrative proceedings, and financial assurance (bonding) requirements with regulatory bodies. Management is in discussion with all concerned parties and does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows. However, there can be no assurance that such discussions will result in a manageable outcome or that we will be able to meet financial assurance (bonding) requirements. If Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected. See “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies” for additional information.

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.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

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

50

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

Exhibits Index

No.  Description 

10.1	Amendment No. 1 to Line of Credit, Guarantee and Security Agreement, dated as of September 3, 2019, among Pilot Travel Centers LLC, Nixon Product Storage, LLC and the other loan parties hereto.
31.1*	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
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.

51

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/19

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, 2019	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer, Principal Financial Officer, and Principal Accounting Officer)

52

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 quarterly 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 periods covered by this quarterly report;

3.

Based on my knowledge, the financial statements and other financial information included in this quarterly 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 quarterly report;

4.

I am 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 I have:

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my 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 quarterly report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this quarterly report based on such evaluation; and

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

5.

I have disclosed, based on my 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:

(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, 2019

/s/ JONATHAN P. CARROLL

Jonathan P. Carroll

Chief Executive Officer, President, Assistant Treasurer and Secretary

(Principal Executive Officer and Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER AND

PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Blue Dolphin Energy Company (the “Blue Dolphin”) on Form 10-Q for the period ended September 30, 2019 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer and Principal Financial Officer) of Blue Dolphin, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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 Blue Dolphin.

/s/ JONATHAN P. CARROLL

Jonathan P. Carroll

Chief Executive Officer, President, Assistant Treasurer and Secretary

(Principal Executive Officer and Principal Financial Officer)

November 14, 2019

XML

16. Income Taxes (Details 2) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Beginning balance	$ 46,949	$ 39,833
Net operating losses	6,460	7,116
Ending balance	53,409	46,949
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	37,325	30,219
Net operating losses	6,460	7,116
Ending balance	$ 43,795	$ 37,325

XML

15. Leases (Details 3) $ in Thousands	Sep. 30, 2019 USD ($)
Operating Lease
2020	$ 172
2021	189
2022	209
2023	212
Total minimum rental payments	782
Finance Lease
2020	17
2021	73
2022	0
2023	0
Total minimum rental payments	90
Total
2020	189
2021	262
2022	209
2023	212
Total minimum rental payments	$ 872

XML

6. Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 537	$ 437
Prepaid crude oil and condensate	525	1,166
Prepaid easement renewal fees	127	143
Other prepaids	75	40
Prepaid expenses, net	$ 1,264	$ 1,786

XML

9. Related Party Transactions (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Prepaid operating expenses, related party	$ 9,932	$ 8,575
Less: Long-term debt, related party, current portion, in default	(7,918)	(7,041)
Less: Interest payable, related party, in default	(2,014)	(1,534)
Long-term debt - net of current portion, related party	0	0
LEH [Member]
Prepaid operating expenses, related party	6,882	6,145
LEH [Member] | June LEH Note [Member]
Prepaid operating expenses, related party	868	611
LEH [Member] | BDPL Loan Agreement [Member]
Prepaid operating expenses, related party	6,014	5,534
Ingleside [Member] | March Ingleside Note [Member]
Prepaid operating expenses, related party	1,345	1,283
Jonathan Carroll [Member] | March Carroll Note [Member]
Prepaid operating expenses, related party	$ 1,705	$ 1,147

XML

7. Inventory (Tables)

9 Months Ended

Sep. 30, 2019

Inventory Disclosure [Abstract]

Inventory

	September 30,		December 31,
	2019		2018
	(in thousands)
Crude oil and condensate	$	1,177	$	861
AGO		285		276
Chemicals		142		106
Naphtha		99		143
Propane		25		17
LPG mix		6		5
HOBM		-		102
	$	1,734	$	1,510

XML

19. Subsequent Event

9 Months Ended

Sep. 30, 2019

Subsequent Events [Abstract]

Subsequent Event

On November 11, 2019, LE entered into a long-term crude supply contract with Pilot. The crude supply contract has a volume-based, initial term of approximately 24.8 million bbls, after which time the contract renews on a 1-year evergreen basis until either party terminates the contract. Pilot may terminate the contract by giving LE sixty (60) days prior written notice at any time during the term of the contract. LE may terminate the contract upon expiration of the initial term or at any time during a renewal term by giving Pilot sixty (60) days prior written notice. As consideration for LE entering into the crude supply contract for an extended term, Pilot paid LE a one-time payment of $2.5 million.

XML

12. Line of Credit Payable (Tables)

9 Months Ended

Sep. 30, 2019

Line of Credit Facility [Abstract]

Line of credit

	September 30,			December 31,
	2019			2018
	(in thousands)
Amended Pilot Line of Credit	$	12,689		$	-
Less: Unamortized debt issue costs		(407	)		-
Less: Interest payable, short-term		(102	)		-
	$	12,180		$	-

XML

16. Income Taxes (Tables)

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income tax benefit (expense)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Current
Federal	$	-	$	-	$	-	$	108
State		-		-		-		-
Deferred
Change in valuation allowance		-		-		-		109
Total provision for income taxes	$	-	$	-	$	-	$	217

Deferred tax assets and deferred tax liabilities

	September 30,			December 31,
	2019			2018
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	12,618		$	11,260
Accrued arbitration award payable		-			2,850
Business interest expense		1,695			704
Start-up costs (crude oil and condensate processing facility)		615			678
Asset retirement obligations liability/deferred revenue		541			542
AMT credit and other		50			108
Total deferred tax assets		15,519			16,142
Deferred tax liabilities:
Basis differences in property and equipment		(5,767	)		(5,153	)
Total deferred tax liabilities		(5,767	)		(5,153	)
		9,752			10,989
Valuation allowance		(9,702	)		(10,881	)
Deferred tax assets, net	$	50		$	108

NOL carryforwards

	Net Operating Loss Carryforward
	Pre-Ownership Change		Post-Ownership Change		Total
	(in thousands)
Balance at December 31, 2017	$	9,614	$	30,219	$	39,833
Net operating losses		-		7,116		7,116
Balance at December 31, 2018	$	9,614	$	37,335	$	46,949
Net operating losses		-		6,460		6,460
Balance at September 30, 2019	$	9,614	$	43,795	$	53,409

XML

15. Leases

9 Months Ended

Sep. 30, 2019

Leases, Operating [Abstract]

Leases

We adopted the new lease accounting guidance using the modified retrospective method and applied it to all leases based on the contract terms in effect as of January 1, 2019. For existing contracts, we carried forward our historical assessment of: (i) whether contracts are or contain leases, (ii) lease classification, and (iii) initial direct costs.

As of September 30, 2019, leases were as follow:

● Office Lease (Operating Lease). BDSC has an office lease related to our principal office space in Houston, Texas. The 68-month operating lease expires in 2023. BDSC has the option to extend the lease term for one additional five (5) year period if notice of intent to extend is provided to the lessor at least twelve (12) months before the end of the current term. LEH subleases a portion of this leased office space (see “Note (9) Related-Party Transactions” related to the LEH office sub-lease agreement).  Sublease income received from LEH totaled $0.01 million for both three-month periods ended September 30, 2019 and 2018. Sublease income received from LEH totaled $0.03 million for both nine-month periods ended September 30, 2019 and 2018.

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

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

For leases with terms greater than 12 months, including renewal options when appropriate, we record the related right-of-use asset and lease liability as the present value of the fixed lease payments over the lease term. Since the leases do not provide a readily-determinable discount rate, we use the incremental borrowing rate to discount lease payments to present value. The following table presents the lease-related assets and liabilities recorded on the consolidated balance sheet:

	Classification on	Septeber 30,
	Consolidated Balance Sheet	2019
		(in thousands)
Assets
Operating lease right-of-use assets	Operating lease right-of-use assets	$	787
Less: Accumulated amortization on operating lease assets	Operating lease right-of-use assets		(102	)
			685
Finance lease assets	Property and equipment, net		180
Less: Accumulated amortization on finance lease assets	Property and equipment, net		(26	)
			154
Total lease assets		$	839
Liabilities
Current
Operating lease	Current portion of lease liabilities	$	172
Finance leases	Current portion of lease liabilities		90
			262
Noncurrent
Operating lease	Long-term lease liabilities, net of current		610
Total lease liabilities		$	872

Weighted average remaining lease term in years
Operating lease	3.92
Finance leases	0.59
Weighted average discount rate
Operating lease	8.25	%
Finance leases	8.25	%

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019		2019
	(in thousands)
Operating lease costs	$	51	$	154
Finance lease costs:
Depreciation of leased assets		4		12
Interest on lease liabilities		2		4
Total lease cost	$	57	$	170

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019		2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating lease	$	40	$	81
Operating cash flows for finance leases		2		4
Financing cash flows for finance leases		13		35

As of September 30, 2019, maturities of lease liabilities for the periods indicated were as follows:

	Operating Lease		Financing Leases		Total
	(in thousands)
2020	$	172	$	17	$	189
2021		189		73		262
2022		209		-		209
2023		212		-		212
	$	782	$	90	$	872

As of September 30, 2019, our future minimum annual lease commitments that are non-cancelable for the periods indicated are as follow:

	Operating
	Lease
2020		230
2021		233
2022		236
2023		219
	$	918

XML

11. Long-Term Debt and Accrued Interest

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt and Accrued Interest

Outstanding Balances. Our Long-term debt consists of: (i) a LE $25.0 million loan with Veritex (the “First Term Loan Due 2034”), (ii) a LRM $10.0 million loan with Veritex (the “Second Term Loan Due 2034”), and (iii) a LE loan with Notre Dame Investors, Inc. as evidenced by a promissory note that is currently held by John Kissick (the “Notre Dame Debt”). As described within this “Note (11”) Long-Term Debt and Accrued Interest,” certain of our long-term debt is currently in default. See “Note (9) Related-Party Transactions” for additional disclosures regarding long-term debt, related party and accrued interest payable, related party.

We adopted new ASU guidance related to leases. As a result, disclosures previously reported in this “Note (11”) Long-Term Debt and Accrued Interest” as capital leases are now reported in “Note (15) Leases” as finance leases. See “Note (3) Significant Accounting Policies – New Pronouncements Adopted” for information related to the new lease accounting standard.

Long-term debt, which represents outstanding principal and accrued interest, as of the dates indicated was as follows:

	September 30,			December 31,
	2019			2018
	(in thousands)
First Term Loan Due 2034 (in default)	$	22,178		$	22,593
Second Term Loan Due 2034 (in default)		9,197			9,353
Notre Dame Debt (in default)		8,418			7,821
Capital lease		-			41
	$	39,793		$	39,808
Less: Current portion of long-term debt, net		(34,151	)		(34,863	)
Less: Unamortized debt issue costs		(1,910	)		(2,006	)
Less: Accrued interest payable (in default)		(3,732	)		(2,939	)
	$	-		$	-

Unamortized debt issue costs related to long-term debt as of the dates indicated consisted of the following:

	September 30,			December 31,
	2019			2018
	(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		(532	)		(436	)
	$	1,910		$	2,006

Amortization expense was $0.03 million for the three months ended September 30, 2019 and 2018. Amortization expense was $0.9 million for the nine months ended September 30, 2019 and 2018.

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

	September 30,			December 31,
	2019			2018
	(in thousands)
Notre Dame Debt (in default)	$	3,440		$	2,843
First Term Loan Due 2034 (in default)		182			43
Second Term Loan Due 2034 (in default)		110			53
		3,732			2,939
Less: Accrued interest payable (in default)		(3,732	)		(2,939	)
Long-term interest payable, net of current portion	$	-		$	-

USDA-Guaranteed Loans. The First Term Loan Due 2034 and Second Term Loan Due 2034 are guaranteed 100% by the USDA. The USDA, acting through its agencies, administers a federal rural credit program that makes direct loans and guarantees portions of loans made and serviced by USDA-qualified lenders for various purposes. Each USDA guarantee is a full faith and credit obligation of the United States with the USDA guaranteeing up to 100% of the principal amount of guaranteed loans. The lender on each USDA-guaranteed loan is required by regulation to retain the unguaranteed portion of the guaranteed loan, to service the entire underlying guaranteed loan, including the USDA-guaranteed portion and the unguaranteed portion, and to remain mortgage and/or secured party of record. The USDA-guaranteed portion and the unguaranteed portion of the loan are to be secured by the same collateral with equal lien priority. The USDA-guaranteed portion of a loan cannot be paid later than, or in any way be subordinated to, the related unguaranteed portion.

Amended and Restated Guaranty Fee Agreements. As a condition of the First Term Loan Due 2034 and Second Term Loan Due 2034, Jonathan Carroll was required to provide a guarantee for repayment of funds borrowed and interest accrued under the USDA-guaranteed loans. LEH, LRM and Blue Dolphin also cross-guaranteed the First Term Loan Due 2034 and Second Term Loan Due 2034. (See “Note (9) Related-Party Transactions” for additional disclosures related to LEH, Jonathan Carroll, and the Amended and Restated Guaranty Fee Agreements, as well as a breakdown of guaranty fee expenses incurred related to the First Term Loan Due 2034 and Second Term Loan Due 2034.)

Defaults in USDA-Guaranteed Loan Agreements. As described elsewhere in this Quarterly Report, Veritex notified LE and LRM that the Final Arbitration Award constituted an event of default under the First Term Loan Due 2034 and the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2019, 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 First Term Loan Due 2034 and Second Term Loan 2034. LE also failed to replenish a payment reserve account as required under the First Term Loan Due 2034. The occurrence of events of default under the First Term Loan Due 2034 and Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 and Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE and LRM’s obligations under the loan agreements, and/or exercise any other rights and remedies available. Veritex did not accelerate or call due the First Term Loan Due 2034 and Second Term Loan Due 2034 considering the Settlement Agreement. Instead, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and Second Term Loan Due 2034 and informed LE and LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements.

Veritex worked with LE and LRM and was aware and party to all discussions and arrangements with GEL surrounding the Settlement Agreement, all amendments, and the final and effective Settlement with GEL. In the Veritex Consent, Veritex agreed to waive certain covenant defaults and forbear from enforcing its remedies under the secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of the $1.0 million payment reserve account as required under the First Term Loan Due 2034 on or before August 31, 2019. As of the filing date of this Quarterly Report, the payment reserve account had not been fully replenished. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 and Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations. (See “Note (1) Organization – Going Concern” and “– Operating Risks” for additional disclosures related to the First Term Loan Due 2034 and Second Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

Key Terms of Long-Term Debt.

First Term Loan Due 2034 (In Default). Key terms of the First Term Loan Due 2034 are as follow:

Principal Amount:	$25.0 million
Maturity Date:	June 2034
Principal and Interest Payment:	$0.2 million monthly
Interest Rate:	Wall Street Journal Prime Rate plus 2.75%

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, which is 100% USDA-guaranteed, is secured by: (i) a first lien on the Nixon Facility’s 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.

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.

Second Term Loan Due 2034 (In Default). Key terms of the Second Term Loan Due 2034 are as follow:

Principal Amount:	$10.0 million
Maturity Date:	December 2034
Principal and Interest Payment:	$0.1 million monthly
Interest Rate:	Wall Street Journal Prime Rate plus 2.75%

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, which is 100% USDA-guaranteed, 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 a term loan that matured in 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.

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.

Notre Dame Debt (In Default). Key terms of the Notre Dame Debt are as follow:

Original Principal Amount:	$8.0 million
Additional Principal:	$3.7 million
Maturity Date:	January 2018
Principal and Interest Payment:	None; payment rights subordinated to senior lender
Default Interest Rate:	16.00%

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. 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’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034. To date, there have been no payments under the Notre Dame Debt.

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.

XML

7. Inventory

9 Months Ended

Sep. 30, 2019

Inventory Disclosure [Abstract]

Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,		December 31,
	2019		2018
	(in thousands)
Crude oil and condensate	$	1,177	$	861
AGO		285		276
Chemicals		142		106
Naphtha		99		143
Propane		25		17
LPG mix		6		5
HOBM		-		102
	$	1,734	$	1,510

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2019	Dec. 31, 2018
STOCKHOLDERS' DEFICIT
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,975,514	10,975,514
Common stock, shares outstanding	10,975,514	10,975,514

XML

2. Basis of Presentation

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [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 Article 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, 2018 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, 2019 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2019, or for any other period.

XML

14. Concentration of Risk (Details Narrative) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Balances in excess of FDIC insurance limit	$ 400	$ 1,200

XML

11. Long-Term Debt and Accrued Interest (Details 2) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Notre Dame Debt (in default)	$ 3,440	$ 2,843
First Term Loan Due 2034	182	43
Second Term Loan Due 2034	110	53
Total	3,732	2,939
Less: Interest payable, in default	(3,732)	(2,939)
Long term debt	$ 0	$ 0

XML

13. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

	September 30,			December 31,
	2019			2018
	(in thousands)
Asset retirement obligations, at the beginning of the period	$	2,580		$	2,315
Accretion expense		-			265
		2,580			2,580
Less: asset retirement obligations, current portion		(2,580	)		(2,580	)
Long-term asset retirement obligations, at the end of the period	$	-		$	-

XML

17. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2019

Earnings Per Share [Abstract]

Earnings per share

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019		2018
	(in thousands, except share and per share amounts)
Net income (loss)	$	8,167	$	(937	)	$	5,615	$	748
Basic and diluted income (loss) per share	$	0.74	$	(0.09	)	$	0.51	$	0.07
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,975,514		10,925,513			10,975,514		10,925,513

XML

10. Accrued Expenses and Other Current Liabilities

9 Months Ended

Sep. 30, 2019

Other Liabilities, Current [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,
	2019		2018
	(in thousands)
Unearned revenue	$	1,207	$	434
Board of director fees payable		370		273
Insurance		232		61
Other payable		223		265
Property taxes		161		48
Excise and income taxes payable		93		47
Customer deposits		10		109
Easement payable		-		223
Accrued rent		-		111
	$	2,296	$	1,571

XML

6. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 2019

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,
	2019		2018
	(in thousands)
Prepaid insurance	$	537	$	437
Prepaid crude oil and condensate		525		1,166
Prepaid easement renewal fees		127		143
Other prepaids		75		40
	$	1,264	$	1,786

XML

14. Concentration of Risk

9 Months Ended

Sep. 30, 2019

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, 2019 and December 31, 2018, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $0.4 million and $1.2 million, respectively.

Key Supplier. Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We have a long-term crude supply contract in place with Pilot. In connection with the crude supply contract, Pilot stores its crude oil at the Nixon Facility pursuant to a terminal services agreement Pilot currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect Pilot to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected by net losses, working capital deficits, and financial covenant defaults in secured loan agreements. (See “Note (19) Subsequent Event” for additional disclosures related to the crude supply contract.)

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, 2019, we had 4 customers that accounted for approximately 98% of our refined petroleum product sales. LEH, a related party, was 1 of these 4 significant customers and accounted for approximately 32% of our refined petroleum product sales.  At September 30, 2019, these 4 customers represented approximately $0.6 million in accounts receivable.  LEH represented approximately $0.3 million in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related-Party Transactions,” “Note (11) Long-Term Debt and Accrued Interest,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.)

For the nine months ended September 30, 2019, we had 4 customers that accounted for approximately 98% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 31% of our refined petroleum product sales.  At September 30, 2019, these 4 customers represented approximately $0.6 million in accounts receivable.  LEH represented approximately $0.3 million in accounts receivable.

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.

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.

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,
	2019				2018				2019				2018
	(in thousands, except percent amounts)
LPG mix	$	8	0.0	%	$	-	0.0	%	$	17	0.0	%	$	3	0.0	%
Naphtha		14,147	18.2	%		24,127	25.5	%		43,358	19.5	%		64,093	25.2	%
Jet fuel		25,035	32.3	%		27,299	28.9	%		70,017	31.4	%		73,415	28.9	%
HOBM		17,044	22.0	%		21,735	23.0	%		49,951	22.5	%		60,594	23.8	%
AGO		21,303	27.5	%		21,307	22.6	%		59,309	26.6	%		56,140	22.1	%
	$	77,537	100.0	%	$	94,468	100.0	%	$	222,652	100.0	%	$	254,245	100.0	%

XML

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 584	$ 14
Restricted cash	49	49
Accounts receivable, net	336	379
Accounts receivable, related party	321	0
Prepaid expenses and other current assets	1,264	1,786
Deposits	162	194
Inventory	1,734	1,510
Refundable federal income tax	166	108
Total current assets	4,616	4,040
LONG-TERM ASSETS
Total property and equipment, net	64,412	64,697
Operating lease right-of-use assets	685	0
Restricted cash, noncurrent	547	1,602
Surety bonds	230	230
Deferred tax assets, net	50	108
Total long-term assets	65,924	66,637
TOTAL ASSETS	70,540	70,677
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion, in default	34,151	34,863
Line of credit payable	12,180	0
Long-term debt, related party, current portion, in default	7,918	7,041
Accrued interest payable (in default)	3,834	2,939
Accrued interest payable, related party (in default)	2,014	1,534
Accounts payable	2,265	2,719
Accounts payable, related party	2,042	1,529
Current portion of lease liabilities	262	0
Asset retirement obligations, current portion	2,580	2,580
Accrued expenses and other current liabilities	2,296	1,571
Accrued arbitration award payable	0	21,128
Total current liabilities	69,542	75,904
LONG-TERM LIABILITIES
Long-term operating leases, net of current portion	610	0
Total long-term liabilities	610	0
TOTAL LIABILITIES	70,152	75,904
Commitments and contingencies (Note 18)
STOCKHOLDERS' DEFICIT
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,975,514 shares issued at September 30, 2019 and December 31, 2018)	110	110
Additional paid-in capital	36,936	36,936
Retained earnings (deficit)	(36,658)	(42,273)
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)	388	(5,227)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$ 70,540	$ 70,677

XML

1. Organization

9 Months Ended

Sep. 30, 2019

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 in Nixon, Texas, primarily include a 15,000-bpd crude distillation tower and more than 1.0 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 owned 79.8% of our common stock, par value $0.01 per share (the “Common Stock”) at September 30, 2019. (See “Note (9) Related-Party Transactions,” “Note (11) Long-Term Debt and Accrued Interest” 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”).

See “Part I, Item 1. Business” and “Part I, Item 2. Properties” in our 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:

Defaults Under Veritex Secured Loan Agreements. LE and LRM each have loans with Veritex Community Bank (“Veritex”), as successor in interest to Sovereign Bank (“Sovereign”) by merger, in the original aggregate amount of $35.0 million. These Veritex loans are guaranteed 100% by the U.S. Department of Agriculture (“USDA”).

● Events of Default. Veritex delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constituted an event of default under the secured loan agreements. The occurrence of an event of default permitted 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 did not accelerate or call due the secured loan agreements considering the Settlement Agreement. Instead, 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.

● Financial Covenant Defaults. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2019, 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 sheets at September 30, 2019 and December 31, 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.

Veritex worked with LE and LRM and was aware and party to all discussions and arrangements with GEL surrounding the Settlement Agreement, all amendments, and the final and effective Settlement with GEL. In a notice to obligors dated April 30, 2019 (the "Veritex Consent'), Veritex agreed to waive certain covenant defaults and forbear from enforcing its remedies under the secured loan agreements subject to: (i) the agreement and concurrence of the USDA and (ii) the replenishment of a payment reserve account in the amount of $1.0 million as required by one of the secured loan agreements on or before August 31, 2019. As of the filing date of this Quarterly Report, the payment reserve account had not been fully replenished. Any exercise by Veritex of its rights and remedies under such secured loan agreements would have a material adverse effect on our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations. In such a case, the trading price of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

Net Losses and Working Capital Deficits. For the three months ended September 30, 2019, we reported net income of $8.2 million, or $0.74 per share. Excluding the $9.1 million gain on extinguishment of debt, we would have reported a net loss of $1.0 million, or a loss of $0.09 per share, for the three months ended September 30, 2019. Comparatively, we reported a net loss of $0.9 million, or a loss of $0.09 per share, for the three months ended September 30, 2018.

For the nine months ended September 30, 2019, we reported net income of $5.6 million, or $0.51 per share. Excluding the $9.1 million gain on extinguishment of debt, we would have reported a net loss of $3.5 million, or $0.32 per share, for the nine months ended September 30, 2019. This compares to reported net income of $0.7 million, or income of $0.07 per share, for the nine months ended September 30, 2018.

We had a working capital deficit of $64.9 million and $71.9 million at September 30, 2019 and December 31, 2018, respectively. Excluding the current portion of long-term debt, we had a working capital deficit of $22.9 million and $30.0 at September 30, 2019 at December 31, 2018, respectively.

For additional disclosures related to defaults under secured loan agreements and other long-term debt, see “Item 1. Financial Statements – Note (11) Long-Term Debt and Accrued Interest” and “ – Note (9) Related Party Transactions” in this Quarterly Report. For additional disclosures related to the Settlement Agreement, refer to “Item 1. Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Final Arbitration Award and Settlement Agreement” in the Quarterly Report, as well as “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the period ended December 31, 2018 (the “Annual Report”).

Operating Risks. Successful execution of our business strategy depends on several key factors, including, having adequate working capital to meet operational needs and regulatory requirements, maintaining safe and reliable operations at the Nixon Facility, meeting contractual obligations, and having favorable margins on refined petroleum products. During the three months ended September 30, 2019, management successfully finalized the Settlement with GEL and realized a $9.1 million gain on the extinguishment of the liability, and management believes that it is continuing to take other steps to further improve our operations and financial stability. However, there can be no assurance that our business strategy 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 or meet financial assurance (bonding) requirements on commercially reasonable terms or at all. If Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

For additional disclosures related to our business strategy and risk factors that could materially affect our future business, financial condition and results of operations, refer to “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Results of Operations” and “Liquidity and Capital Resources” in this Quarterly Report, as well as “Part I, Item 1. Business – Business Strategy,” “Part I, Item 1A. Risk Factors,” and “Part I, Item 3. Legal Proceedings” in our Annual Report.

XML

14. Concentration of Risk (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Total refined petroleum product sales	$ 77,537	$ 94,468	$ 222,652	$ 254,245
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 8	$ 0	$ 17	$ 3
Concentration Risk	0.00%	0.00%	0.00%	0.00%
Naphtha
Total refined petroleum product sales	$ 14,147	$ 24,127	$ 43,358	$ 64,093
Concentration Risk	18.20%	25.50%	19.50%	25.20%
Jet Fuel
Total refined petroleum product sales	$ 25,035	$ 27,299	$ 70,017	$ 73,415
Concentration Risk	32.30%	28.90%	31.40%	28.90%
HOBM
Total refined petroleum product sales	$ 17,044	$ 21,735	$ 49,951	$ 60,594
Concentration Risk	22.00%	23.00%	22.50%	23.80%
AGO
Total refined petroleum product sales	$ 21,303	$ 21,307	$ 59,309	$ 56,140
Concentration Risk	27.50%	22.60%	26.60%	22.10%

XML

11. Long-Term Debt and Accrued Interest (Details 1) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 1,674	$ 1,674
Second Term Loan Due 2034	768	768
Less: Accumulated amortization	(532)	(436)
Long term debt	$ 1,910	$ 2,006

XML

16. Income Taxes (Details 1) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 12,618	$ 11,260
Accrued arbitration award payable	0	2,850
Business interest expense	1,695	704
Start-up costs (crude oil and condensate processing facility)	615	678
Asset retirement obligations liability/deferred revenue	541	542
AMT credit and other	50	108
Total deferred tax assets	15,519	16,142
Deferred tax liabilities:
Basis differences in property and equipment	(5,767)	(5,153)
Total deferred tax liabilities	(5,767)	(5,153)
Deferred tax assets, net	9,752	10,989
Valuation allowance	(9,702)	(10,881)
Deferred tax assets, net	$ 50	$ 108

XML

15. Leases (Details 2) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases [Abstract]
Operating cash flows for operating lease	$ 40	$ 81
Operating cash flows for finance leases	2	4
Financing cash flows for finance leases	$ 13	$ 35

XML

18. Commitments and Contingencies (Details) $ in Thousands	Sep. 30, 2019 USD ($)
Amounts received to reduce the outstanding balance of the Final Arbitration Award	$ 22,200
Initial payment (September 2017)
Amounts received to reduce the outstanding balance of the Final Arbitration Award	3,700
Interim Payments (July 2018 to April 2019)
Amounts received to reduce the outstanding balance of the Final Arbitration Award	8,000
Settlement Payment (May 2019)
Amounts received to reduce the outstanding balance of the Final Arbitration Award	10,000
Deferred Interim Installment Payments (June 2019 to July 2019)
Amounts received to reduce the outstanding balance of the Final Arbitration Award	$ 500

XML

7. Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Inventory Disclosure [Abstract]
Crude oil and condensate	$ 1,177	$ 861
AGO	285	276
Chemicals	142	106
Naphtha	99	143
Propane	25	17
LPG mix	6	5
HOBM	0	102
Inventories, net	$ 1,734	$ 1,510

XML

9. Related Party Transactions (Details 1) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Total revenues	$ 78,633	$ 95,543	$ 225,905	$ 256,904
Total revenues, percent	100.00%	100.00%	100.00%	100.00%
LEH [Member]
Refinery operations revenues	$ 25,034	$ 27,299	$ 70,016	$ 73,415
Refinery operations revenues, percent	31.80%	28.70%	31.00%	28.60%
Other Customers [Member]
Refinery operations revenues	$ 52,503	$ 67,169	$ 152,636	$ 180,830
Tolling and terminaling revenues	$ 1,096	$ 1,075	$ 3,253	$ 2,659
Refinery operations revenues, percent	66.80%	70.40%	67.60%	70.40%
Tolling and terminaling revenues, percent	1.40%	0.90%	1.40%	1.00%

XML

6. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2019

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

Prepaid balances

	September 30,		December 31,
	2019		2018
	(in thousands)
Prepaid insurance	$	537	$	437
Prepaid crude oil and condensate		525		1,166
Prepaid easement renewal fees		127		143
Other prepaids		75		40
	$	1,264	$	1,786

XML

18. Commitments and Contingencies

9 Months Ended

Sep. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Legal Matters.

Final Arbitration Award and Settlement Agreement.  As previously disclosed, LE was involved in the GEL Arbitration with GEL, an affiliate of Genesis, related to a contractual dispute involving the Crude Supply Agreement and Joint Marketing Agreement, each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered 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 $31.3 million.

In July 2018, the Lazarus Parties and GEL entered into the Settlement Agreement. The Settlement Agreement was subsequently amended five times to extend the Settlement Payment Date and/or modify certain terms related to the Interim Payments or the Settlement Payment. During the period September 2017 to August 2019, GEL received the following amounts from the Lazarus Parties to reduce the outstanding balance of the Final Arbitration Award:

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

The Lazarus Parties made all payments to GEL as required for the Settlement to be final and effective. As a result: (i) the Settlement occurred on August 23, 2019, (ii) the mutual releases became effective, (iii) GEL filed a stipulation of dismissal of claims against LE, and (iv) Blue Dolphin recognized a $9.1 million gain on the extinguishment of debt on its consolidated statements of operations for the three and nine months ended September 30, 2019. Until the Settlement occurred, the debt was reflected on Blue Dolphin’s consolidated balance sheets as accrued arbitration award payable. At September 30, 2019 and December 31, 2018, accrued arbitration award payable was $0 and $21.1million, respectively.

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

Other Legal Matters. We are involved in lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens, contract-related disputes, administrative proceedings, and financial assurance (bonding) requirements with regulatory bodies. Management is in discussion with all concerned parties and does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows. However, there can be no assurance that such discussions will result in a manageable outcome or that we will be able to meet financial assurance (bonding) requirements. If Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.

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

Financing Agreements. See “Note (11) Long-Term Debt and Accrued Interest” and “Note (12) Line of Credit Payable” for additional disclosures related to financing agreements.

Guarantees. LEH and Jonathan Carroll 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 and Accrued Interest” for additional disclosures related to guarantees.

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

Nixon Facility Expansion. 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 a petroleum storage tank.

Supplemental Pipeline Bonds. In a letter dated March 30, 2018, BOEM ordered BDPL to provide additional supplemental bonds or acceptable financial assurance of approximately $4.8 million (the “Separate Orders”) within sixty (60) calendar days of receipt of the letter. The Separate Orders relate to five (5) existing pipeline rights-of-way. BOEM issued an Incident of Noncompliance (“INC”) for each Separate Order dated June 8, 2018 (the “June 2018 INCs”) and received by BDPL on June 11, 2018. BOEM asserts that the June 2018 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 June 2018 INCs on August 8, 2018. The Interior Board of Land Appeals (the “IBLA”) granted multiple extension requests that extended BDPL’s deadline for filing a Statement of Reasons. On August 9, 2019, BDPL timely filed its Statement of Reasons with the IBLA. On October 16, 2019, BOEM filed a motion requesting a 30-day extension to file its answer to BDPL’s Statement of Reasons. BOEM filed its answer to BDPL’s Statement of Reasons, requesting that the IBLA affirm the June 2018 INCs. In light of BDPL’s August 2018 meeting with BSEE, BDPL intends to request a stay in the IBLA matter until August 2020. The Office of the Solicitor of the U.S. Department of the Interior (the “Solicitor's Office”) was agreeable to a 10-day extension while it conferred with BOEM on BDPL’s stay request. On October 31, 2019, BDPL filed a motion to request the 10-day extension, which motion was subsequently granted by the IBLA. The Solicitor's Office consented to an additional 14-day extension, until November 22, 2019, for BDPL to file its reply. On November 8, 2019, BDPL filed a motion to request the 14-day extension.

BDPL’s pending appeal of the June 2018 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. Members of management met with BOEM and BSEE on August 15, 2019. Based upon discussions with BOEM, BDPL reasonably expects that its pipeline and platform decommissioning obligations, including incremental amounts of supplemental bonds, can be significantly reduced or eliminated, which may serve to partially or fully resolve the Separate Orders and the June 2018 INCs (see “Idle Iron” discussion below). As of September 30, 2019 and December 31, 2018, 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 additional financial assurance or is assessed significant penalties under the June 2018 INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. At this time, we are unable to predict the outcome of the Separate Orders. Accordingly, we have not recorded a liability on our consolidated balance sheet as of September 30, 2019.

Idle Iron. BSEE requires operators to decommission certain wells and platforms that have not been used in the past five (5) years for exploration and development operations or as infrastructure to support such operations. BDPL’s Blue Dolphin Pipeline has been inactive since September 2012. Due to the length of inactivity, BSEE required BDPL to: (i) flush and fill the Blue Dolphin Pipeline, (ii) abandon-in-place a portion of the Blue Dolphin Pipeline’s 20” segment and certain smaller diameter connecting lateral lines that reside offshore in federal waters and (iii) remove from federal waters the GA-288C anchor platform. In April 2016, BDPL submitted decommissioning permit applications to BSEE for three (3) pipeline segments – Segments #13101, #9428, and #15635 – and the GA-288C anchor platform. In June 2016, BDPL also submitted a decommissioning permit application to the U.S. Army Corps of Engineers (“USCOE”) for abandonment of Segment #9428. The permit applications were granted by BSEE at varying dates between August 2016 and April 2017. Work must typically be completed within 120 days from the date of permit approval. The USCOE withdrew BDPL’s decommissioning permit application in April 2018.

In a letter dated December 19, 2018, BSEE issued to BDPL an INC for its failure to flush and fill Segment #13101 (the “December 2018 INC”) pursuant to the pipeline decommissioning approval letter issued in March 2017. Members of management met with BOEM and BSEE on August 15, 2019. BSEE proposed that BDPL submit permit applications for pipeline and platform decommissioning within six (6) months (no later than February 15, 2020), and to develop and implement a safe boarding plan for submission with such permit applications. Further, BSEE proposed that BDPL would need to conduct approved, permitted work in a safe manner within 12 months (no later than August 15, 2020).  If these actions are not addressed within the allowable timeframes, BOEM indicated that BDPL would be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct INCs, civil penalties, and revocation of BDPL’s operator designation. As of the filing date of this Quarterly Report, BDPL engaged a third-party consultant to oversee the abandonment project, and the consultant is preparing the permit applications for submittal to BSEE. If BDPL is unable to comply within BSEE’s designated timetables and is assessed significant penalties by BSEE, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. As of September 30, 2019, BDPL maintained $2.6 million in asset retirement obligations related to abandonment of these assets.

XML

12. Line of Credit Payable

9 Months Ended

Sep. 30, 2019

Line of Credit Facility [Abstract]

Line of Credit Payable

Line of credit payable consists of a line of credit, guarantee and security agreement between Pilot Travel Centers LLC (“Pilot”) and NPS (the “Pilot Line of Credit”). Pilot and NPS entered the Pilot Line of Credit on May 3, 2019. The parties to the Pilot Line of Credit subsequently entered into amendments to the Pilot Line of Credit on May 9, 2019 and May 10, 2019. The parties entered into Amendment No. 1 to the Pilot Line of Credit effective September 3, 2019 (the “Amended Pilot Line of Credit”). The Amended Pilot Line of Credit was fully executed by all parties on September 9, 2019. The Amended Pilot Line of Credit provided for, among other things:

● a $0.2 million increase in the aggregate principal amount available under the line of credit (from $12.8 million to $13.0 million); and

● Pre-payment by NPS to Pilot in a principal amount equal to the amount set forth opposite such date below, together with accrued and unpaid interest thereon:

Date	Principal Amount
September 30, 2019	$0.1 million
October 31, 2019	$0.1 million

As of the filing date of this Quarterly Report,  the September and October payments referenced above had been made.

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

	September 30,			December 31,
	2019			2018
	(in thousands)
Amended Pilot Line of Credit	$	12,689		$	-
Less: Unamortized debt issue costs		(407	)		-
Less: Interest payable, short-term		(102	)		-
	$	12,180		$	-

Key terms of the Amended Pilot Line of Credit are as follow:

Principal Amount:	Up to $13.0 million
Maturity Date:	May 2020
Monthly Payment:	$0.1 million (September and October 2019 only)
Interest Payment:	$0.2 million monthly
Interest Rate:	12.00% per annum

The Amended Pilot Line of Credit was primarily used to fund the Settlement Payment to GEL. Remaining funds are being used to finance NPS' purchase of crude oil from Pilot pursuant to certain purchase and supply contracts and to provide working capital. The Amended Pilot Line of Credit contains customary affirmative and negative covenants and events of default and is secured by (i) NPS receivables, (ii) NPS assets, including a tank lease (the “Tank Lease”), and (iii) LRM receivables. On May 3, 2019, as an inducement to Pilot’s entry into the Pilot Line of Credit, Blue Dolphin and Pilot entered into a Pledge Agreement (the “Pledge Agreement”) whereby Blue Dolphin pledged its equity interests in NPS to Pilot to secure NPS’ obligations under the Pilot Line of Credit. Blue Dolphin, LE, LRM, and LEH have each guaranteed NPS’ obligations under the Pilot Line of Credit. On May 10, 2019, LE, NPS, Pilot and Veritex entered into a Subordination and Attornment Agreement (the “Subordination Agreement”), providing that, if Veritex in its capacity as a secured lender of LE and LRM were to foreclose on LE property that NPS was leasing from LE pursuant to the Tank Lease, Veritex would permit the continued performance of obligations under the Tank Lease so long as certain conditions are met. The effectiveness of the Subordination Agreement is subject to certain conditions, including the agreement and concurrence of the USDA.

XML

8. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2019

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,
	2019			2018
	(in thousands)
Refinery and facilities	$	66,308		$	63,058
Land		566			566
Other property and equipment		833			747
		67,707			64,371
Less: Accumulated depletion, depreciation, and amortization		(12,156	)		(10,429	)
		55,551			53,942
Construction in progress		8,861			10,755
	$	64,412		$	64,697

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 $0.7 million and $1.3 million at September 30, 2019 and December 31, 2018, respectively. Capital expenditures at the Nixon Facility are being funded by working capital derived from revenue from operations and LEH and its affiliates (including Jonathan Carroll), as well as from long-term debt from Veritex that was secured in 2015 for expansion of the Nixon Facility. Unused amounts under the Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. See “Note (11) Long-Term Debt and Accrued Interest” for additional disclosures related to borrowings for capital spending.

XML

11. Long-Term Debt and Accrued Interest (Tables)

9 Months Ended

Sep. 30, 2019

Debt Disclosure [Abstract]

Schedule of long term debt

	September 30,			December 31,
	2019			2018
	(in thousands)
First Term Loan Due 2034 (in default)	$	22,178		$	22,593
Second Term Loan Due 2034 (in default)		9,197			9,353
Notre Dame Debt (in default)		8,418			7,821
Capital lease		-			41
	$	39,793		$	39,808
Less: Current portion of long-term debt, net		(34,151	)		(34,863	)
Less: Unamortized debt issue costs		(1,910	)		(2,006	)
Less: Accrued interest payable (in default)		(3,732	)		(2,939	)
	$	-		$	-

Schedule of debt issue costs

	September 30,			December 31,
	2019			2018
	(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		(532	)		(436	)
	$	1,910		$	2,006

Accrued interest related to our long-term debt, net

	September 30,			December 31,
	2019			2018
	(in thousands)
Notre Dame Debt (in default)	$	3,440		$	2,843
First Term Loan Due 2034 (in default)		182			43
Second Term Loan Due 2034 (in default)		110			53
		3,732			2,939
Less: Accrued interest payable (in default)		(3,732	)		(2,939	)
Long-term interest payable, net of current portion	$	-		$	-

XML

15. Leases (Tables)

9 Months Ended

Sep. 30, 2019

Leases [Abstract]

Schedule of leases

	Classification on	Septeber 30,
	Consolidated Balance Sheet	2019
		(in thousands)
Assets
Operating lease right-of-use assets	Operating lease right-of-use assets	$	787
Less: Accumulated amortization on operating lease assets	Operating lease right-of-use assets		(102	)
			685
Finance lease assets	Property and equipment, net		180
Less: Accumulated amortization on finance lease assets	Property and equipment, net		(26	)
			154
Total lease assets		$	839
Liabilities
Current
Operating lease	Current portion of lease liabilities	$	172
Finance leases	Current portion of lease liabilities		90
			262
Noncurrent
Operating lease	Long-term lease liabilities, net of current		610
Total lease liabilities		$	872

Weighted average remaining lease term in years
Operating lease	3.92
Finance leases	0.59
Weighted average discount rate
Operating lease	8.25	%
Finance leases	8.25	%

Lease costs

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019		2019
	(in thousands)
Operating lease costs	$	51	$	154
Finance lease costs:
Depreciation of leased assets		4		12
Interest on lease liabilities		2		4
Total lease cost	$	57	$	170

Supplemental cash flow information related to leases

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019		2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating lease	$	40	$	81
Operating cash flows for finance leases		2		4
Financing cash flows for finance leases		13		35

Maturities of operating lease liabilities

	Operating Lease		Financing Leases		Total
	(in thousands)
2020	$	172	$	17	$	189
2021		189		73		262
2022		209		-		209
2023		212		-		212
	$	782	$	90	$	872

Future minimum annual lease commitments

	Operating
	Lease
2020		230
2021		233
2022		236
2023		219
	$	918

XML

1. Organization (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss)	$ 8,167	$ (937)	$ 5,615	$ 748
Net loss per common share	$ 0.74	$ (0.09)	$ 0.51	$ 0.07

XML

15. Leases (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Leases [Abstract]
Operating lease right-of-use assets, gross	$ 787
Less: Accumulated amortization on operating lease assets	(102)
Operating lease right-of-use assets, net	685	$ 0
Finance lease assets, gross	180
Less: Accumulated amortization on finance lease assets	(26)
Finance lease assets, net	154
Total lease assets	839
Current portion of operating lease	172
Current portion of finance lease	90
Total current lease liability	262	0
Long-term portion of operating lease	610	$ 0
Total lease liabilities	$ 872
Weighted average remaining lease term in years - operating lease	3 years 11 months 1 day
Weighted average remaining lease term in years - finance lease	7 months 2 days
Weighted average discount rate - operating lease	8.25%
Weighted average discount rate - finance lease	8.25%

XML

12. Line of Credit Payable (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Line of credit, gross	$ 39,793	$ 39,808
Less: Unamortized debt issue costs	(1,910)	(2,006)
Less: Interest payable	(3,732)	(2,939)
Pilot Line of Credit
Line of credit, gross	12,689	0
Less: Unamortized debt issue costs	(407)	0
Less: Interest payable	(102)	0
Line of credit	$ 12,180	$ 0

XML

10. Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Other Liabilities, Current [Abstract]
Unearned revenue	$ 1,207	$ 434
Board of director fees payable	370	273
Insurance	232	61
Other payable	223	265
Property taxes	161	48
Excise and income taxes payable	93	47
Customer deposits	10	109
Easement payable	0	223
Accrued rent	0	111
Accrued Expenses and Other Current Liabilities, Net	$ 2,296	$ 1,571

XML

Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
REVENUE FROM OPERATIONS
Refinery operations	$ 77,537	$ 94,468	$ 222,652	$ 254,245
Tolling and terminaling	1,096	1,075	3,253	2,659
Total revenue from operations	78,633	95,543	225,905	256,904
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	74,163	92,167	213,714	243,245
Other conversion costs	2,066	1,959	6,587	6,463
Total cost of goods sold	76,229	94,126	220,301	249,708
Gross profit	2,404	1,417	5,604	7,196
COST OF OPERATIONS
LEH operating fee	144	154	477	462
Other operating expenses	52	33	165	133
General and administrative expenses	655	929	1,904	2,277
Depletion, depreciation and amortization	632	478	1,855	1,396
Accretion of asset retirement obligations	0	61	0	205
Total cost of operations	1,483	1,655	4,401	4,473
Income (loss) from operations	921	(238)	1,203	2,723
OTHER INCOME (EXPENSE)
Easement, interest and other income	1	18	2	20
Interest and other expense	(1,883)	(760)	(4,718)	(2,255)
Gain on extinguishment of debt	9,128	0	9,128	0
Total other income (expense)	7,246	(742)	4,412	(2,235)
Income (loss) before income taxes	8,167	(980)	5,615	488
Income tax benefit	0	43	0	260
Net income (loss)	$ 8,167	$ (937)	$ 5,615	$ 748
Income (loss) per common share:
Basic	$ 0.74	$ (0.09)	$ 0.51	$ 0.07
Diluted	$ 0.74	$ (0.09)	$ 0.51	$ 0.07
Weighted average number of common shares outstanding:
Basic	10,975,514	10,925,513	10,975,514	10,925,513
Diluted	10,975,514	10,925,513	10,975,514	10,925,513

XML

3. Significant Accounting Policies

9 Months Ended

Sep. 30, 2019

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

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are presented net of any necessary allowance(s) for doubtful accounts. Receivables are recorded at the invoiced amount and generally do not bear interest. An allowance for doubtful accounts is established, when necessary, based on prior experience and other factors which, in management's judgment, deserve consideration in estimating bad debts.  Management assesses collectability primarily based on the current aging status of the customer's account, our historical collection experience with the customer, and the customer's financial condition.  Based on a review of these factors, management establishes or adjusts the allowance for specific customers and the accounts receivable portfolio as a whole.  We had an allowance for doubtful accounts of $0.1 million at both September 30, 2019 and December 31, 2018.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for the periods presented.

Pipelines and Facilities. Our pipelines and facilities are recorded at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with 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, including capitalized interest, relate to construction and refurbishment activities at the Nixon Facility. These expenditures 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.)

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

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

Tolling and Terminaling Revenue. Tolling and terminaling represents 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 cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2019 and December 31, 2018. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”) credit carryforwards. In addition, we have NOL carryforwards that remain available for future use.

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, 2019 and December 31, 2018, 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 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented.

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. The cost estimates for each of our assets were developed based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (13) 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:

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

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

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

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

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

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

ASU 2018-05, Income Taxes (Topic 740).  In March 2018, FASB issued ASU 2018-05. This guidance amends SEC paragraphs in ASC 740, Income Taxes, to reflect Staff Accounting Bulletin No. 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act in the period of enactment.  This guidance also includes amendments to the XBRL Taxonomy.  For public business entities, the amendments in ASU 2018-05 are effective for fiscal years ending after December 15, 2020. Early adoption is permitted.  We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

XML

4. Business Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Net revenues (excluding intercompany fees and sales)	$ 78,633	$ 95,543	$ 225,905	$ 256,904
General and administrative expenses	655	929	1,904	2,277
Net income (loss)	8,167	(937)	5,615	748
Refinery Operations [Member]
Net revenues (excluding intercompany fees and sales)	77,537	94,468	222,652	254,245
Intercompany fees and sales	(668)	(873)	(1,927)	(2,419)
Operation costs and expenses	(76,088)	(93,656)	(219,766)	(248,078)
Segment contribution margin	781	(61)	959	3,748
General and administrative expenses	(292)	(375)	(898)	(929)
Depreciation and amortization	(481)	(432)	(1,429)	(1,258)
Interest and other non-operating income (expenses)	0	0	0	0
Income (loss) before income taxes	0	0	0	0
Income tax benefit	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	964	372	1,375	1,141
Identifiable assets	49,613	51,816	49,613	51,816
Tolling and Terminaling [Member]
Net revenues (excluding intercompany fees and sales)	1,096	1,075	3,253	2,659
Intercompany fees and sales	668	873	1,927	2,419
Operation costs and expenses	(285)	(624)	(1,012)	(2,092)
Segment contribution margin	1,479	1,324	4,168	2,986
General and administrative expenses	(68)	(65)	(173)	(156)
Depreciation and amortization	(99)	(46)	(297)	(138)
Interest and other non-operating income (expenses)	0	0	0	0
Income (loss) before income taxes	0	0	0	0
Income tax benefit	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	0	223	83	767
Identifiable assets	18,994	19,425	18,994	19,425
Corporate & Other [Member]
Net revenues (excluding intercompany fees and sales)	0	0	0	0
Intercompany fees and sales	0	0	0	0
Operation costs and expenses	(52)	(94)	(165)	(338)
Segment contribution margin	(52)	(94)	(165)	(338)
General and administrative expenses	(295)	(489)	(833)	(1,192)
Depreciation and amortization	(52)	0	(129)	0
Interest and other non-operating income (expenses)	0	0	0	0
Income (loss) before income taxes	0	0	0	0
Income tax benefit	0	0	0	0
Net income (loss)	0	0	0	0
Capital expenditures	0	0	0	0
Identifiable assets	1,933	926	1,933	926
Total
Net revenues (excluding intercompany fees and sales)	78,633	95,543	225,905	256,904
Intercompany fees and sales	0	0	0	0
Operation costs and expenses	(76,425)	(94,374)	(220,943)	(250,508)
Segment contribution margin	2,208	1,169	4,962	6,396
General and administrative expenses	(655)	(929)	(1,904)	(2,277)
Depreciation and amortization	(632)	(478)	(1,855)	(1,396)
Interest and other non-operating income (expenses)	7,246	(742)	4,412	(2,235)
Income (loss) before income taxes	8,167	(980)	5,615	488
Income tax benefit	0	43	0	260
Net income (loss)	8,167	(937)	5,615	748
Capital expenditures	964	595	1,458	1,908
Identifiable assets	$ 70,540	$ 72,167	$ 70,540	$ 72,167

XML

8. Property, Plant and Equipment, Net (Details Narrative) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 700	$ 1,300

XML

9. Related Party Transactions (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Related Party Transactions [Abstract]
Accounts payable, related party	$ 2,042		$ 2,042		$ 1,529
Dock Tolling Agreement with LMT fees	50	$ 200	400	$ 600
Lease payments received under the office sub-lease agreement with LEH	$ 10	$ 10	$ 30	$ 30

XML

16. Income Taxes (Details Narrative) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income tax benefit	$ 0	$ (43)	$ 0	$ (260)

XML

15. Leases (Details 4) $ in Thousands	Sep. 30, 2019 USD ($)
Leases [Abstract]
2020	$ 230
2021	233
2022	236
2023	219
Total	$ 918

XML

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

9 Months Ended

Sep. 30, 2019

Property, Plant and Equipment [Abstract]

Property and equipment

	September 30,			December 31,
	2019			2018
	(in thousands)
Refinery and facilities	$	66,308		$	63,058
Land		566			566
Other property and equipment		833			747
		67,707			64,371
Less: Accumulated depletion, depreciation, and amortization		(12,156	)		(10,429	)
		55,551			53,942
Construction in progress		8,861			10,755
	$	64,412		$	64,697

XML

3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2019

Accounting Policies [Abstract]

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

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are presented net of any necessary allowance(s) for doubtful accounts. Receivables are recorded at the invoiced amount and generally do not bear interest. An allowance for doubtful accounts is established, when necessary, based on prior experience and other factors which, in management's judgment, deserve consideration in estimating bad debts.  Management assesses collectability primarily based on the current aging status of the customer's account, our historical collection experience with the customer, and the customer's financial condition.  Based on a review of these factors, management establishes or adjusts the allowance for specific customers and the accounts receivable portfolio as a whole.  We had an allowance for doubtful accounts of $0.1 million at both September 30, 2019 and December 31, 2018.

Inventory

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for the periods presented.

Pipelines and Facilities. Our pipelines and facilities are recorded at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with 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, including capitalized interest, relate to construction and refurbishment activities at the Nixon Facility. These expenditures 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.)

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

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

Tolling and Terminaling Revenue. Tolling and terminaling represents 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 cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2019 and December 31, 2018. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”) credit carryforwards. In addition, we have NOL carryforwards that remain available for future use.

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, 2019 and December 31, 2018, 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 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented.

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. The cost estimates for each of our assets were developed based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (13) 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

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:

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

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

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

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

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

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

ASU 2018-05, Income Taxes (Topic 740).  In March 2018, FASB issued ASU 2018-05. This guidance amends SEC paragraphs in ASC 740, Income Taxes, to reflect Staff Accounting Bulletin No. 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act in the period of enactment.  This guidance also includes amendments to the XBRL Taxonomy.  For public business entities, the amendments in ASU 2018-05 are effective for fiscal years ending after December 15, 2020. Early adoption is permitted.  We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements.

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

XML

16. Income Taxes

9 Months Ended

Sep. 30, 2019

Income Tax Disclosure [Abstract]

Income Taxes

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Current
Federal	$	-	$	-	$	-	$	108
State		-		-		-		-
Deferred
Change in valuation allowance		-		-		-		109
Total provision for income taxes	$	-	$	-	$	-	$	217

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.

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

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

	September 30,			December 31,
	2019			2018
	(in thousands)
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	12,618		$	11,260
Accrued arbitration award payable		-			2,850
Business interest expense		1,695			704
Start-up costs (crude oil and condensate processing facility)		615			678
Asset retirement obligations liability/deferred revenue		541			542
AMT credit and other		50			108
Total deferred tax assets		15,519			16,142
Deferred tax liabilities:
Basis differences in property and equipment		(5,767	)		(5,153	)
Total deferred tax liabilities		(5,767	)		(5,153	)
		9,752			10,989
Valuation allowance		(9,702	)		(10,881	)
Deferred tax assets, net	$	50		$	108

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

NOL Carryforwards. Under IRC Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than fifty (50) percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, relating to a series of private placements, and in 2012, because of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income. In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of approximately $0.6 million per year. Unused portions of the annual use limitation amount may be used in subsequent years. Because of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused. NOL carryforwards that were generated after the 2012 ownership change and prior to 2018 are not subject to an annual use limitation under IRC Section 382 and may be used for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change. NOL carryforwards that were generated after 2017 may only be used to offset 80% of taxable income and are carried forward indefinitely.

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

	Net Operating Loss Carryforward
	Pre-Ownership Change		Post-Ownership Change		Total
	(in thousands)
Balance at December 31, 2017	$	9,614	$	30,219	$	39,833
Net operating losses		-		7,116		7,116
Balance at December 31, 2018	$	9,614	$	37,335	$	46,949
Net operating losses		-		6,460		6,460
Balance at September 30, 2019	$	9,614	$	43,795	$	53,409

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, 2019 and December 31, 2018, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2019 and December 31, 2018.

XML

9. Related Party Transactions (Details 2) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Interest expenses under loan and guarantee, related party	$ 378	$ 371	$ 1,140	$ 1,104
Jonathan Carroll [Member] | Guaranty Fee Agreements [Member]
Interest expenses under loan and guarantee, related party	156	161	471	485
Jonathan Carroll [Member] | March Carroll Note [Member]
Interest expenses under loan and guarantee, related party	33	19	86	34
LEH [Member] | BDPL Loan Agreement [Member]
Interest expenses under loan and guarantee, related party	160	160	480	482
LEH [Member] | June LEH Note [Member]
Interest expenses under loan and guarantee, related party	17	6	40	7
Ingleside [Member] | March Ingleside Note [Member]
Interest expenses under loan and guarantee, related party	$ 12	$ 25	$ 63	$ 96

XML

3. Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 100	$ 100

XML

8. Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 66,308	$ 63,058
Land	566	566
Other property and equipment	833	747
Property, Plant and Equipment, gross	67,707	64,371
Less: Accumulated depletion, depreciation and amortization	(12,156)	(10,429)
Property, plant and equipment, gross	55,551	53,942
Construction in progress	8,861	10,755
Property, plant and equipment, net	$ 64,412	$ 64,697

XML

17. Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Net income (loss)	$ 8,167	$ (937)	$ 5,615	$ 748
Basic and diluted income per share	$ 0.74	$ (0.09)	$ 0.51	$ 0.07
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,975,514	10,925,513	10,975,514	10,925,513

XML

16. Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Current federal	$ 0	$ 0	$ 0	$ 108
Current state	0	0	0	0
Change in valuation allowance	0	0	0	109
Total provision for income taxes	$ 0	$ 43	$ 0	$ 260

XML

4. Revenue and Segment Information (Tables)

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Business segment reporting

	Three Months Ended September 30,
	2019												2018
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Tolling and			Corporate
	Operations			Terminaling			& Other			Total			Operations			Terminaling			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	77,537		$	1,096		$	-		$	78,633		$	94,468		$	1,075		$	-		$	95,543
Intercompany fees and sales		(668	)		668			-			-			(873	)		873			-			-
Operation costs and expenses(1)		(76,088	)		(285	)		(52	)		(76,425	)		(93,656	)		(624	)		(94	)		(94,374	)
Segment contribution margin	$	781		$	1,479		$	(52	)	$	2,208		$	(61	)	$	1,324		$	(94	)	$	1,169
General and administrative expenses		(292	)		(68	)		(295	)		(655	)		(375	)		(65	)		(489	)		(929	)
Depreciation and amortization		(481	)		(99	)		(52	)		(632	)		(432	)		(46	)		-			(478	)
Interest and other non-operating income (expenses), net											7,246												(742	)
Income (loss) before income taxes											8,167												(980	)
Income tax benefit											-												43
Net income (loss)										$	8,167											$	(937	)
Capital expenditures	$	964		$	-		$	-		$	964		$	372		$	223		$	-		$	595
Identifiable assets	$	49,613		$	18,994		$	1,933		$	70,540		$	51,816		$	19,425		$	926		$	72,167

(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 use 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,
	2019												2018
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Tolling and			Corporate
	Operations			Terminaling			& Other			Total			Operations			Terminaling			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	222,652		$	3,253		$	-		$	225,905		$	254,245		$	2,659		$	-		$	256,904
Intercompany fees and sales		(1,927	)		1,927			-			-			(2,419	)		2,419			-			-
Operation costs and expenses(1)		(219,766	)		(1,012	)		(165	)		(220,943	)		(248,078	)		(2,092	)		(338	)		(250,508	)
Segment contribution margin	$	959		$	4,168		$	(165	)	$	4,962		$	3,748		$	2,986		$	(338	)	$	6,396
General and administrative expenses		(898	)		(173	)		(833	)		(1,904	)		(929	)		(156	)		(1,192	)		(2,277	)
Depreciation and amortization		(1,429	)		(297	)		(129	)		(1,855	)		(1,258	)		(138	)		-			(1,396	)
Interest and other non-operating income (expenses), net											4,412												(2,235	)
Income before income taxes											5,615												488
Income tax benefit											-												260
Net income										$	5,615											$	748
Capital expenditures	$	1,375		$	83		$	-		$	1,458		$	1,141		$	767		$	-		$	1,908
Identifiable assets	$	49,613		$	18,994		$	1,933		$	70,540		$	51,816		$	19,425		$	926		$	72,167

(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 use costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

XML

17. Earnings Per Share

9 Months Ended

Sep. 30, 2019

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,
	2019		2018			2019		2018
	(in thousands, except share and per share amounts)
Net income (loss)	$	8,167	$	(937	)	$	5,615	$	748
Basic and diluted income (loss) per share	$	0.74	$	(0.09	)	$	0.51	$	0.07
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,975,514		10,925,513			10,975,514		10,925,513

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 three and nine months ended September 30, 2019 and 2018 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

XML

9. Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Accounts payable, related party

	September 30,			December 31,
	2019			2018
	(in thousands)
LEH
June LEH Note (in default)	$	868		$	611
BDPL Loan Agreement (in default)		6,014			5,534
LEH total		6,882			6,145
Ingleside
March Ingleside Note (in default)		1,345			1,283
Jonathan Carroll
March Carroll Note (in default)		1,705			1,147
		9,932			8,575
Less: Long-term debt, related party, current portion, in default		(7,918	)		(7,041	)
Less: Accrued interest payable, related party (in default)		(2,014	)		(1,534	)
	$	-		$	-

Refinery operating expenses

	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	(in thousands, except percent amounts)
Refinery operations
LEH	$	25,034	31.8	%	$	27,299	28.7	%	$	70,016	31.0	%	$	73,415	28.6	%
Other customers		52,503	66.8	%		67,169	70.4	%		152,636	67.6	%		180,830	70.4	%
Tolling and terminaling
Other customers		1,096	1.4	%		1,075	0.9	%		3,253	1.4	%		2,659	1.0	%
	$	78,633	100.0	%	$	95,543	100.0	%	$	225,905	100.0	%	$	256,904	100.0	%

Accrued interest expenses

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Jonathan Carroll
Guaranty Fee Agreements
First Term Loan Due 2034	$	110	$	114	$	333	$	344
Second Term Loan Due 2034		46		47		138		141
March Carroll Note (in default)		33		19		86		34
LEH
BDPL Loan Agreement (in default)		160		160		480		482
June LEH Note (in default)		17		6		40		7
Ingleside
March Ingleside Note (in default)		12		25		63		96
	$	378	$	371	$	1,140	$	1,104

XML

13. Asset Retirement Obligations

9 Months Ended

Sep. 30, 2019

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, and we depreciated the amount added to property and equipment and recognized accretion expense relating to the discounted liability over the remaining life of the asset. At December 31, 2018, the liability was fully accreted.

Due to the length of inactivity of our pipelines and facilities assets, BDPL is required by the Bureau of Ocean Energy Management (“BOEM”) to abandon-in-place certain pipelines and remove an anchor platform in federal waters. Members of management met with BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) on August 15, 2019. BSEE mandated BDPL to submit permit applications for pipeline and platform decommissioning within six (6) months (no later than February 15, 2020), and to develop and implement a safe boarding plan for submission with such permit applications. Further, BDPL must conduct approved, permitted work within 12 months (no later than August 15, 2020).  If these actions are not addressed within the allowable timeframes, BOEM indicated that BDPL will be subject to vigorous regulatory oversight and enforcement, including but not limited to failure to correct INCs, civil penalties, and revocation of BDPL’s operator designation. As of the filing date of this Quarterly Report, BDPL engaged a third-party consultant to oversee the abandonment project, and the consultant is preparing the permit applications for submittal to BSEE. If BDPL is unable to comply within BSEE’s designated timetables and is assessed significant penalties by BSEE, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. Plugging and abandonment costs will be 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,
	2019			2018
	(in thousands)
Asset retirement obligations, at the beginning of the period	$	2,580		$	2,315
Accretion expense		-			265
		2,580			2,580
Less: asset retirement obligations, current portion		(2,580	)		(2,580	)
Long-term asset retirement obligations, at the end of the period	$	-		$	-

XML

9. Related Party Transactions

9 Months Ended

Sep. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

Related Parties. 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-party transactions consist of the following 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 owned 79.8% of our Common Stock at September 30, 2019. 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) an office sublease-agreement with BDSC.

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 Texas Refinery I, LLC (“LTRI”). LTRI is a related party of LEH and Jonathan Carroll. During the quarter ended September 30, 2019, LE purchased refurbished refinery equipment from LTRI for use at the Nixon Facility.

Lazarus Marine Terminal I, LLC (“LMT”). LMT is a related party of LEH and Jonathan Carroll. LE was party to a Dock Tolling Agreement with LMT that was terminated during the quarter ended September 30, 2019.

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. The guaranty fee agreements and the promissory note relate to LE and LRM USDA-guaranteed loans.

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) on 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. The Board plans to review the Amended and Restated Operating Agreement during the first quarter of 2020 to evaluate renewal.

LEH receives a management fee calculated as 5% of certain of our direct operating expenses. During the fourth quarter of 2018, the management fee was changed to be calculated based on year to date operating expenses incurred, regardless of whether they were paid for by LEH or LE. The management fee was previously reflected within refinery operating expenses in our consolidated statements of operations. The management fee is currently reflected as the ‘LEH operating fee’ 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, 2020 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.

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 had a five-year term. Under the agreement, LE paid LMT a flat reservation fee monthly. The reservation fee included tolling volumes up to 84,000 gallons per day. Excess tolling volumes were subject to an increased per gallon rate. The Dock Tolling Agreement was terminated effective July 1, 2019. Amounts expensed as tolling fees under the Dock Tolling Agreement are reflected in cost of goods sold in our consolidated statements of operations.

Office Sub-Lease Agreement. In January 2018, BDSC entered into an Office Space Agreement with LEH to lease office space at our headquarters building in Houston, Texas. The Office Space Agreement has a term of sixty-eight (68) months expiring on August 31, 2023. Under the Office Space Agreement, LEH’s base rent is approximately $0.02 million per month. The Office Space Agreement includes rent abatement periods.

Refinery Equipment Purchase. In July 2019, LE purchased two (2) refurbished heat exchangers from LTRI. The total purchase price was $160,000. The cost is reflected in accounts payable, related party in our consolidated balance sheets.

Financial Agreements. We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. LEH and its affiliates (Ingleside and Jonathan Carroll) have provided working capital to Blue Dolphin in the form of a term loan and non-cash advances (such as conversion of accounts payable to debt under 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 financial agreements are reflected in long-term debt, related party, current portion in our consolidated balance sheets.

BDPL Loan Agreement (In Default). BDPL has a 2016 loan agreement and related security agreement with LEH as lender (the “BDPL Loan Agreement”). The BDPL Loan Agreement is currently in default due to non-payment. Key terms of the BDPL Loan Agreement are as follow:

Principal Amount:	$4.0 million
Maturity Date:	August 2018
Principal and Interest Payment:	$500,000 annually
Interest Rate:	16.00%

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 accrued interest payable, related party, current portion in our consolidated balance sheets. To date, there have been no payments under the BDPL Loan Agreement.

Promissory Notes (In Default). Working capital provided to Blue Dolphin in the form of non-cash advances whereby accounts payable, related party was converted to debt under promissory notes are reflected below. The promissory notes matured in January 2019. Interest, which is compounded annually, is still accruing at a rate of 8.00% and is reported as part of the outstanding balance. Promissory notes to LEH, Ingleside and Jonathan Carroll, which are reflected within long-term debt, related party, are currently in default.

● June LEH Note. The June LEH Note reflects amounts owed to LEH at September 30, 2019 under the Amended and Restated Operating Agreement.

● March Ingleside Note. The March Ingleside Note reflects amounts owed to Ingleside at September 30, 2019 under the Amended and Restated Tank Lease Agreement.

● March Carroll Note. The March Carroll Note reflects amounts owed to Jonathan Carroll at September 30, 2019 under the guaranty fee agreements. See “Amended and Restated Guaranty Fee Agreements” below for additional information.

Amended and Restated Guaranty Fee Agreements. Jonathan Carroll was required to provide a guarantee for repayment of funds borrowed and interest accrued under certain LE and LRM USDA-guaranteed loans. For his personal guarantee, LE and LRM each 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 loan agreements. Effective in April 2017, the Guaranty Fee Agreements were amended and restated (the “Amended and Restated Guaranty Fee Agreements”) to reflect payment 50% in cash and 50% in Blue Dolphin Common Stock. Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, current portion in our consolidated balance sheets. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

As previously disclosed, the Lazarus Parties were prohibited by GEL from making payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements (see also “Note (18) Commitments and Contingencies – Legal Matters – Final Arbitration Award and Settlement Agreement”). Now that the Settlement between GEL and the Lazarus Parties is final and effective, management has resumed payments of the common stock component to Mr. Carroll under the agreements. On November 14, 2019, Mr. Carroll received 1,351,851 shares of Common Stock, which represents payment of the common stock component of the guaranty fees for the period May 2017 through October 2019. Mr. Carroll will receive payment of the common stock component of the guaranty fees on a quarterly basis going forward. Currently, management does not intend on paying Mr. Carroll the cash portion due to Blue Dolphin’s working capital deficits. The cash portion of guaranty fees owed to Mr. Carroll will continue to be accrued and added to the principal balance of the March Carroll Note.

Financial Statements Impact.

Consolidated Balance Sheets. Accounts payable, related party to LMT associated with the Dock Tolling Agreement totaled $1.8 million and $1.5 million at September 30, 2019 and December 31, 2018, respectively. Accounts payable, related party to LTRI related to the purchase of refinery equipment totaled $0.2 million and $0 at September 30, 2019 and December 31, 2018, respectively.

Long-term debt, related party, current portion and accrued interest payable, related party, as of the dates indicated was as follows:

	September 30,			December 31,
	2019			2018
	(in thousands)
LEH
June LEH Note (in default)	$	868		$	611
BDPL Loan Agreement (in default)		6,014			5,534
LEH total		6,882			6,145
Ingleside
March Ingleside Note (in default)		1,345			1,283
Jonathan Carroll
March Carroll Note (in default)		1,705			1,147
		9,932			8,575
Less: Long-term debt, related party, current portion, in default		(7,918	)		(7,041	)
Less: Accrued interest payable, related party (in default)		(2,014	)		(1,534	)
	$	-		$	-

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	(in thousands, except percent amounts)
Refinery operations
LEH	$	25,034	31.8	%	$	27,299	28.7	%	$	70,016	31.0	%	$	73,415	28.6	%
Other customers		52,503	66.8	%		67,169	70.4	%		152,636	67.6	%		180,830	70.4	%
Tolling and terminaling
Other customers		1,096	1.4	%		1,075	0.9	%		3,253	1.4	%		2,659	1.0	%
	$	78,633	100.0	%	$	95,543	100.0	%	$	225,905	100.0	%	$	256,904	100.0	%

Fees associated with the Dock Tolling Agreement with LMT totaled $0.05 million for the three months ended September 30, 2019 compared to $0.2 million for the three months ended September 30, 2018. Fees associated with the Dock Tolling Agreement with LMT totaled $0.4 million and $0.6 million for the nine-month periods ended September 30, 2019 and 2018, respectively.

Lease payments received under the office sub-lease agreement with LEH totaled $0.01 million for the three months ended September 30, 2019 and 2018. Lease payments received under the office sub-lease agreement with LEH totaled $0.03 million for the nine months ended September 30, 2019 and 2018.

The LEH operating fee totaled approximately $0.1 million in the three months ended September 30, 2019 compared to $0.2 million for the three months ended September 30, 2018. For both nine-month periods ended September 30, 2019 and 2018, the LEH operating fee totaled approximately $0.5 million.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Jonathan Carroll
Guaranty Fee Agreements
First Term Loan Due 2034	$	110	$	114	$	333	$	344
Second Term Loan Due 2034		46		47		138		141
March Carroll Note (in default)		33		19		86		34
LEH
BDPL Loan Agreement (in default)		160		160		480		482
June LEH Note (in default)		17		6		40		7
Ingleside
March Ingleside Note (in default)		12		25		63		96
	$	378	$	371	$	1,140	$	1,104

XML

18. Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Amounts from the Lazarus Parties toward reducing the outstanding balance of the Final Arbitration Award

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

XML

10. Accrued Expenses and Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2019

Other Liabilities, Current [Abstract]

Accrued expenses and other current liabilities

	September 30,		December 31,
	2019		2018
	(in thousands)
Unearned revenue	$	1,207	$	434
Board of director fees payable		370		273
Insurance		232		61
Other payable		223		265
Property taxes		161		48
Excise and income taxes payable		93		47
Customer deposits		10		109
Easement payable		-		223
Accrued rent		-		111
	$	2,296	$	1,571

XML

14. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 2019

Risks and Uncertainties [Abstract]

Percentages of all refined petroleum products sales to total sales

	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	(in thousands, except percent amounts)
LPG mix	$	8	0.0	%	$	-	0.0	%	$	17	0.0	%	$	3	0.0	%
Naphtha		14,147	18.2	%		24,127	25.5	%		43,358	19.5	%		64,093	25.2	%
Jet fuel		25,035	32.3	%		27,299	28.9	%		70,017	31.4	%		73,415	28.9	%
HOBM		17,044	22.0	%		21,735	23.0	%		49,951	22.5	%		60,594	23.8	%
AGO		21,303	27.5	%		21,307	22.6	%		59,309	26.6	%		56,140	22.1	%
	$	77,537	100.0	%	$	94,468	100.0	%	$	222,652	100.0	%	$	254,245	100.0	%

XML

13. Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period			$ 2,580	$ 2,315	$ 2,315
Accretion expense	$ 0	$ 61	0	$ 205	265
Asset retirement obligations	2,580		2,580		2,580
Less: asset retirement obligations, current portion	(2,580)		(2,580)		(2,580)
Long-term asset retirement obligations, at the end of the period	$ 0		$ 0		$ 0

XML

11. Long-Term Debt and Accrued Interest (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Principal balance outstanding	$ 39,793	$ 39,808
Less: Current portion of long-term debt, net	(34,151)	(34,863)
Less: Unamortized debt issue costs	(1,910)	(2,006)
Less: Interest payable (in default)	(3,732)	(2,939)
Long term debt	0	0
First Term Loan Due 2034 [Member]
Principal balance outstanding	22,178	22,593
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,197	9,353
Notre Dame Debt [Member]
Principal balance outstanding	8,418	7,821
Capital Leases [Member]
Principal balance outstanding	$ 0	$ 41

XML

15. Leases (Details 1) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Leases [Abstract]
Operating lease costs	$ 51	$ 154
Depreciation of leased assets	4	12
Interest on lease liabilities	2	4
Total lease cost	$ 57	$ 170

XML

4. Revenue and Segment Information

9 Months Ended

Sep. 30, 2019

Segment Reporting [Abstract]

Revenue and Segment Information

We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility.

Revenue from Contracts with Customers.

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

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

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

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

	Three Months Ended September 30,
	2019												2018
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Tolling and			Corporate
	Operations			Terminaling			& Other			Total			Operations			Terminaling			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	77,537		$	1,096		$	-		$	78,633		$	94,468		$	1,075		$	-		$	95,543
Intercompany fees and sales		(668	)		668			-			-			(873	)		873			-			-
Operation costs and expenses(1)		(76,088	)		(285	)		(52	)		(76,425	)		(93,656	)		(624	)		(94	)		(94,374	)
Segment contribution margin	$	781		$	1,479		$	(52	)	$	2,208		$	(61	)	$	1,324		$	(94	)	$	1,169
General and administrative expenses		(292	)		(68	)		(295	)		(655	)		(375	)		(65	)		(489	)		(929	)
Depreciation and amortization		(481	)		(99	)		(52	)		(632	)		(432	)		(46	)		-			(478	)
Interest and other non-operating income (expenses), net											7,246												(742	)
Income (loss) before income taxes											8,167												(980	)
Income tax benefit											-												43
Net income (loss)										$	8,167											$	(937	)
Capital expenditures	$	964		$	-		$	-		$	964		$	372		$	223		$	-		$	595
Identifiable assets	$	49,613		$	18,994		$	1,933		$	70,540		$	51,816		$	19,425		$	926		$	72,167

(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 use 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,
	2019												2018
	(in thousands)
	Segments												Segment
	Refinery			Tolling and			Corporate						Refinery			Tolling and			Corporate
	Operations			Terminaling			& Other			Total			Operations			Terminaling			& Other			Total
Net revenues (excluding intercompany fees and sales)	$	222,652		$	3,253		$	-		$	225,905		$	254,245		$	2,659		$	-		$	256,904
Intercompany fees and sales		(1,927	)		1,927			-			-			(2,419	)		2,419			-			-
Operation costs and expenses(1)		(219,766	)		(1,012	)		(165	)		(220,943	)		(248,078	)		(2,092	)		(338	)		(250,508	)
Segment contribution margin	$	959		$	4,168		$	(165	)	$	4,962		$	3,748		$	2,986		$	(338	)	$	6,396
General and administrative expenses		(898	)		(173	)		(833	)		(1,904	)		(929	)		(156	)		(1,192	)		(2,277	)
Depreciation and amortization		(1,429	)		(297	)		(129	)		(1,855	)		(1,258	)		(138	)		-			(1,396	)
Interest and other non-operating income (expenses), net											4,412												(2,235	)
Income before income taxes											5,615												488
Income tax benefit											-												260
Net income										$	5,615											$	748
Capital expenditures	$	1,375		$	83		$	-		$	1,458		$	1,141		$	767		$	-		$	1,908
Identifiable assets	$	49,613		$	18,994		$	1,933		$	70,540		$	51,816		$	19,425		$	926		$	72,167

(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 use costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion).

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Nov. 14, 2019
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, 2019
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 Shell Company	false
Entity Common Stock, Shares Outstanding		12,327,365
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2019

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
OPERATING ACTIVITIES
Net income (loss)	$ 8,167	$ (937)	$ 5,615	$ 748
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization			1,855	1,396
Deferred income tax			0	(216)
Amortization of debt issue costs			409	96
Guaranty fees paid in kind			471	0
Accretion of asset retirement obligations	0	61	0	205	$ 265
Gain on extinguishment of debt	(9,128)	0	(9,128)	0
Changes in operating assets and liabilities
Accounts receivable			43	(312)
Accounts receivable, related party			(321)	653
Prepaid expenses and other current assets			522	760
Deposits and other assets			32	(65)
Inventory			(224)	462
Accrued arbitration award			(12,000)	(4,000)
Accounts payable, accrued expenses and other liabilities			1,689	1,023
Accounts payable, related party			513	404
Net cash provided by (used in) operating activities			(10,524)	1,154
INVESTING ACTIVITIES
Capital expenditures			(1,458)	(1,826)
Net cash used in investing activities			(1,458)	(1,826)
FINANCING ACTIVITIES
Proceeds from line of credit			12,402	0
Payments on debt			(990)	(723)
Payments of debt issuance costs			(322)	0
Net activity on related-party debt			407	924
Net cash provided by financing activities			11,497	201
Net change in cash, cash equivalents, and restricted cash			(485)	(471)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD			1,665	2,146	2,146
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$ 1,180	$ 1,675	1,180	1,675	$ 1,665
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable and capital leases			86	82
Line of credit closing costs included in principal balance			322	0
Interest paid			2,261	2,173
Income taxes paid			$ 0	$ 0