10-Q

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

­

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, 2017

 or

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

For the transition period from to

Commission File No. 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

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

 (713) 568-4725

Registrant’s telephone number, including area code

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

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

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☑
(Do not check if a 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 16, 2017:  10,818,371

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

TABLE OF CONTENTS

GLOSSARY OF SELECTED OIL AND GAS TERMS	3
PART I.  FINANCIAL INFORMATION	5
ITEM 1.  FINANCIAL STATEMENTS	5
Consolidated Balance Sheets (Unaudited)	5
Consolidated Statements of Operations (Unaudited)	6
Consolidated Statements of Cash Flows (Unaudited)	7
Notes to Consolidated Financial Statements	8
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	36
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
ITEM 4. CONTROLS AND PROCEDURES	57
PART II OTHER INFORMATION	60
ITEM 1.  LEGAL PROCEEDINGS	58
ITEM 1A.  RISK FACTORS	58
ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
ITEM 3.  DEFAULTS UPON SENIOR SECURITIES	60
ITEM 4.  MINE SAFETY DISCLOSURES	60
ITEM 5.  OTHER INFORMATION	60
ITEM 6.  EXHIBITS	61
SIGNATURES	62

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

 GLOSSARY OF SELECTED OIL AND GAS TERMS

The following are abbreviations and definitions of certain commonly used oil and gas industry terms that are used in this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 (this “Quarterly Report”):

Atmospheric gas oil (“AGO”). The heaviest product boiled by a crude distillation unit operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. Blended AGO usually serves as the premium quality component used to lift lesser streams to the standards of saleable furnace oil or diesel engine fuel. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock.

Barrel (“bbl”). One stock tank bbl, or 42 U.S. gallons of liquid volume, used about oil or other liquid hydrocarbons.

Blending. The physical mixture of several different liquid hydrocarbons to produce a finished product with certain desired characteristics. Products can be blended in-line through a manifold system, or batch blended in tanks and vessels. In-line blending of gasoline, distillates, jet fuel and kerosene is accomplished by injecting proportionate amounts of each component into the main stream where turbulence promotes thorough mixing. Additives, including octane enhancers, metal deactivators, anti-oxidants, anti-knock agents, gum and rust inhibitors, and detergents, are added during and/or after blending to result in specifically desired properties not inherent in hydrocarbons.

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 oil distillation unit.  The higher a refinery’s complexity, the greater the refinery’s capital investment and number of operating units used to separate feedstock into fractions, improve their quality, and increase the production of higher-valued products. Refinery complexities range from the relatively simple crude oil distillation unit (“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.  Condensate is chemically more complex than LPG.  Although condensate is sometimes like crude oil, it is usually lighter.

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 our LPG mix and 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. Lighter products produced in this process can be further refined in a catalytic cracking unit or reforming unit. Heavier products, which cannot be vaporized and separated in this process, can be further distilled in a vacuum distillation unit or coker.

Distillation tower. A tall column-like vessel in which crude oil and condensate is heated and its vaporized components distilled by means of distillation trays.

Feedstocks. Crude oil and other hydrocarbons, such as condensate and/or intermediate products, that are used as basic input materials in a refining process.  Feedstocks are transformed into one or more finished products.

Finished petroleum products.  Materials or products which have received the final increments of value through processing operations, and which are being held in inventory for delivery, sale, or use.

Intermediate petroleum products.  A petroleum product that might require further processing before it is saleable to the ultimate consumer.  This further processing might be done by the producer or by another processor.  Thus, an intermediate petroleum product might be a final product for one company and an input for another company that will process it further.

Jet fuel. A high-quality kerosene product primarily used in aviation.  Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.

Kerosene. A middle distillate fraction of crude oil that is produced at higher temperatures than naphtha and lower temperatures than gas oil.  It is usually used as jet turbine fuel and sometimes for domestic cooking, heating, and lighting.

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.

Liquefied petroleum gas (“LPG”).  Manufactured during the refining of crude oil and condensate; burns relatively cleanly with no soot and very few sulfur emissions.

MMcf.One million cubic feet; a measurement of gas volume only.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

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.

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 LPGs. The others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. (See also definition of LPG.)

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, 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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	September 30,	December 31,
	2017	2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$44,931	$1,152,628
Restricted cash	1,500,380	3,347,835
Accounts receivable, net	627,604	2,022,166
Accounts receivable, related party	1,060,154	1,161,589
Prepaid expenses and other current assets	1,631,352	1,046,191
Deposits	138,957	138,957
Inventory	2,775,440	2,075,538
Total current assets	7,778,818	10,944,904
Total property and equipment, net	64,396,811	62,324,463
Restricted cash, noncurrent	150,530	1,582,305
Surety bonds	230,000	205,000
Trade name	303,346	303,346
Total long-term assets	65,080,687	64,415,114
TOTAL ASSETS	$72,859,505	$75,360,018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion	$35,756,045	$31,712,336
Long-term debt, related party, current portion	4,000,000	500,000
Accounts payable	2,759,479	14,552,383
Accounts payable, related party	823,200	369,600
Asset retirement obligations, current portion	17,065	17,510
Accrued expenses and other current liabilities	1,220,074	1,281,582
Accrued arbitration award payable	27,627,863	-
Interest payable, current portion	2,659,786	323,756
Total current liabilities	74,863,512	48,757,167
Long-term liabilities:
Asset retirement obligations, net of current portion	2,225,661	2,010,129
Deferred revenues and expenses	52,119	83,390
Long-term debt less unamortized debt issue costs, net of current portion	-	1,300,000
Long-term debt, related party, net of current portion	1,451,655	4,814,690
Long-term interest payable, net of current portion	-	1,691,383
Total long-term liabilities	3,729,435	9,899,592
TOTAL LIABILITIES	78,592,947	58,656,759
Commitments and contingencies (Note 18)
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,818,371 and
10,624,714 shares issued at September 30,2017 and December 31, 2016, respectively)	108,184	106,248
Additional paid-in capital	36,877,604	36,818,528
Accumulated deficit	(42,719,230)	(19,421,517)
Treasury stock (0 and 150,000 shares at cost at September 30, 2017 and December 31, 2016, respectively)	-	(800,000)
Total stockholders' equity (deficit)	(5,733,442)	16,703,259
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$72,859,505	$75,360,018

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
REVENUE FROM OPERATIONS
Refined petroleum product sales	$66,132,959	$53,951,293	$174,667,617	$126,546,716
Tank rental revenue	766,133	717,487	2,173,555	1,624,461
Other operations	-	19,526	-	71,865
Total revenue from operations	66,899,092	54,688,306	176,841,172	128,243,042
COST OF OPERATIONS
Cost of refined products sold	58,785,827	51,689,474	165,185,276	125,316,249
Refinery operating expenses	1,758,005	3,153,646	6,222,771	9,468,409
Joint Marketing Agreement profit share	-	965,627	-	392,062
Other operating expenses	67,969	100,974	183,095	298,566
Arbitration award and associated fees	-	-	24,338,628	-
General and administrative expenses	1,239,813	891,210	2,854,294	1,503,533
Depletion, depreciation and amortization	455,437	504,719	1,355,780	1,415,519
Bad debt recovery	-	-	-	(139,868)
Accretion expense	71,844	28,186	215,532	84,558
Total cost of operations	62,378,895	57,333,836	200,355,376	138,339,028
Income (loss) from operations	4,520,197	(2,645,530)	(23,514,204)	(10,095,986)
OTHER INCOME (EXPENSE)
Easement, interest and other income	26,657	157,840	409,739	415,700
Interest and other expense	(601,335)	(485,659)	(2,027,748)	(1,305,125)
Gain on disposal of property	-	-	1,834,500	-
Total other income (expense)	(574,678)	(327,819)	216,491	(889,425)
Income (loss) before income taxes	3,945,519	(2,973,349)	(23,297,713)	(10,985,411)
			-
Income tax benefit	-	1,034,798	-	3,735,040
Net income (loss)	$3,945,519	$(1,938,551)	$(23,297,713)	$(7,250,371)
Income (loss) per common share:
Basic	$0.36	$(0.19)	$(2.19)	$(0.69)
Diluted	$0.36	$(0.19)	$(2.19)	$(0.69)
Weighted average number of common shares outstanding:
Basic	10,818,371	10,464,715	10,644,654	10,460,849
Diluted	10,818,371	10,464,715	10,644,654	10,460,849

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2017	2016
OPERATING ACTIVITIES
Net loss	$(23,297,713)	$(7,250,371)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depletion, depreciation and amortization	1,355,780	1,415,519
Unrealized gain on derivatives	-	1,143,490
Deferred tax benefit	-	(3,735,040)
Amortization of debt issue costs	96,363	96,364
Accretion of asset retirement obligations	215,532	84,558
Common stock issued for services	30,000	50,000
Recovery of bad debt	-	(139,868)
Changes in operating assets and liabilities
Accounts receivable	1,394,563	(1,815,584)
Accounts receivable, related party	101,435	-
Prepaid expenses and other current assets	(585,161)	945,539
Deposits and other assets	(25,000)	570,444
Inventory	(699,902)	(1,011,662)
Accrued arbitration award	27,627,863	-
Accounts payable, accrued expenses and other liabilities	(12,802,731)	5,269,224
Accounts payable, related party	453,600	(300,000)
Net cash used in operating activities	(6,135,371)	(4,677,387)
INVESTING ACTIVITIES
Capital expenditures	(1,777,219)	(11,255,725)
Net cash used in investing activities	(1,777,219)	(11,255,725)
FINANCING ACTIVITIES
Proceeds from issuance of debt	3,677,953	6,898,931
Payments on debt	(1,120,267)	(1,414,406)
Net activity on related-party debt	967,977	-
Net cash provided by financing activities	3,525,663	5,484,525
Net decrease in cash, cash equivalents, and restricted cash	(4,386,927)	(10,448,587)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	6,082,768	20,645,652
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$1,695,841	$10,197,065
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	$1,650,910	$2,601,709
Financing of guaranty fees via long-term debt, related party	$170,636	$-
Conversion of related-party notes to common stock	$831,012	$-
Interest paid	$1,573,996	$1,827,794
Income taxes paid	$-	$-

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements

(1) Organization

Nature of Operations.  Blue Dolphin Energy Company (“Blue Dolphin,”) is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000-bpd crude oil and condensate processing facility located in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own pipeline assets and have leasehold interests in oil and gas properties. (See “Note (4) Business Segment Information” for further discussion of our business segments.)

Structure and Management.Blue Dolphin was formed as a Delaware corporation in 1986.  We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”). LEH operates and manages all our properties pursuant to an Amended and Restated Operating Agreement (the “Amended and Restated Operating Agreement”).  Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. Together LEH and Jonathan Carroll own approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). (See “Note (8) Related Party Transactions,” “Note (10) Long-Term Debt, Net” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Amended and Restated Operating Agreement, and Jonathan Carroll.)

Our operations are conducted through the following active subsidiaries:

●

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

●

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

●

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

●

Blue Dolphin Petroleum Company, a Delaware corporation.

●

Blue Dolphin Services Co., a Texas corporation.

See "Part I, Item 1. Business and Item 2. Properties” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding our operating subsidiaries, principal facilities, and assets.

References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires.

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

● 

Final GEL Arbitration Award – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all of the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages, legal and administrative fees and court costs to GEL in the aggregate amount of approximately $31.3 million.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

Under the GEL Letter Agreement, GEL could have terminated the GEL Letter Agreement on the 45th day of the Continuance Period, or November 1, 2017, if it determined, in its sole discretion, that settlement discussions between the parties were not advancing to an acceptable resolution. As previously disclosed, on November 1, 2017, LE and GEL amended the GEL Letter Agreement (the “Amended GEL Letter Agreement”) to extend the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017. The Amended GEL Letter Agreement prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period. If the parties are unable to reach an acceptable settlement with Genesis and GEL and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially affected, and we likely would be required to seek protection under bankruptcy laws.

● 

Veritex Secured Loan Agreement Event of Default – Veritex Community Bank (“Veritex”), as successor in interest to Sovereign Bank by merger, has delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex has informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements in light of the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM's ability to meet financial covenants in the secured loan agreements in the future.

We are currently evaluating the effects of the Final Arbitration Award on our business, financial condition and results of operations. In addition to the matters described above, the Final Arbitration Award could materially and adversely affect our ability to procure adequate amounts of crude oil and condensate or our relationships with our customers. The contract-related dispute has negatively affected our customer relationships, prevented us from taking advantage of business opportunities, disrupted refinery operations, diverted management’s focus away from running the business, and impacted our ability to obtain financing.

We can provide no assurance as to whether negotiations with GEL will result in a settlement or as to the potential terms of any such settlement or whether Veritex would approve any such settlement. If LE is unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially adversely affected and we likely would be required to seek protection under bankruptcy laws.

 

Operating Risks.  Successful execution of our business plan depends on several key factors, including having adequate crude oil and condensate supplies, increasing sales of refined petroleum products, and meeting contractual obligations. For the three and nine months ended September 30, 2017, execution of our business plan was negatively impacted by several factors, including:

●

Net Losses – We saw an improvement in net income for the three months ended September 30, 2017.  For the three months ended September 30, 2017, we reported net income of $3,945,519, or income of $0.36 per share, compared to a net loss of $1,938,551, or a loss of $0.19 per share, for the three months ended September 30, 2016.  The $0.55 per share increase between the periods was primarily the result of favorable refining margins in the current three-month period. For the nine months ended September 30, 2017, we reported a net loss of $23,297,713, or a loss of $2.19 per share, compared to a net loss of $7,250,371, or a loss of $0.69 per share, for the nine months ended September 30, 2016.  The $1.50 per share increase in net loss between the periods was primarily the result of the Final Arbitration Award.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

●

Working Capital Deficits – We had a working capital deficit of $67,084,694 at September 30, 2017 compared to a working capital deficit of $37,812,263 at December 31, 2016. Excluding long-term debt, we had a working capital deficit of $27,328,649 at September 30, 2017, compared to working capital of $5,599,927 at December 31, 2016. The significant increase in working capital deficit between the periods primarily related to the Final Arbitration Award and a decrease in cash and cash equivalents.

●

Termination of Relationship with Genesis and GEL – As previously disclosed and discussed elsewhere in this Quarterly Report, LE ceased purchases of crude oil and condensate from GEL under the Crude Supply Agreement in November 2016 and suspended the marketing and sale of refined petroleum products under the Joint Marketing Agreement following the processing of all crude oil and condensate supplied by GEL.

●

Crude Supply Issues – We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by the contract-related dispute with GEL and other factors, as noted above.  The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts of crude oil and condensate from our current supplier or otherwise.

●

Financial Covenant Defaults – In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM's ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to any proposed settlement with GEL or provide future waivers of any financial covenant defaults, which may have an adverse impact on our financial position and results of operations.

During the nine months ended September 30, 2017, we continued aggressive actions to improve operations and liquidity.  We began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure.  We also completed construction of several new petroleum storage tanks at the Nixon Facility. Increasing petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 17,000 bpd, and (iii) provides an opportunity to generate additional tank rental revenue by leasing to third-parties.  Additional ongoing efforts to improve operations and liquidity include restructuring customer contracts on more favorable terms as they come up for renewal.  Management believes that it is taking the appropriate steps to improve our financial stability.  However, there can be no assurance that our plan will be successful, LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all.  Among other factors, the Final Arbitration Award could prevent us from successfully executing our plan.

10

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

●

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

-  

Note (8) Related Party Transactions

-  

Note (10) Long-Term Debt, Net

-  

Note (18) Commitments and Contingencies –Legal Matters

-  

Note (19) Subsequent Events

●

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

-  

GEL Contract-Related Dispute and Final Arbitration Award

-  

Results of Operations

-  

Liquidity and Capital Resources

●

Part II, Item 1. Legal Proceedings

●

Part II, Item 1A. Risk Factors

(2) Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. 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, 2016 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, 2017 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2017, 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.  Cash and cash equivalents were $44,931 at September 30, 2017 compared to cash and cash equivalents of $1,152,628 at December 31, 2016.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

Restricted Cash.Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies.  Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks. At September 30, 2017, total restricted cash was $1,650,910, comprised of restricted cash (current portion) totaling $1,500,380 and restricted cash, noncurrent totaling $150,530.  At December 31, 2016, total restricted cash was $4,930,140, comprised of restricted cash (current portion) totaling $3,347,835 and restricted cash, noncurrent totaling $1,582,305(See “Note (10) Long-Term Debt, Net” for additional disclosures related to our loan agreements with Veritex.)

Accounts Receivable and Allowance for Doubtful Accounts.Our accounts receivable consists of customer obligations due in the ordinary course of business.  Since we have a small number of customers with individually large amounts due on any given date, we evaluate potential and existing customers’ financial condition, credit worthiness, and payment history to minimize credit risk. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods. If necessary, we establish an allowance for doubtful accounts to estimate the amount of probable credit losses.  Allowance for doubtful accounts totaled $0 both at September 30, 2017 and December 31, 2016.

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 refined products sold.  (See “Note (6) Inventory” for additional disclosures related to our inventory.)

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets for any period 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”) 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.  However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

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

(See “Note (7) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name.  At September 30, 2017 and December 31, 2016, trade name totaled $303,346. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2016. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2016.

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability.  (See “Note (10) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

Revenue Recognition.

Refined Petroleum Products Revenue. Revenue from the sale of refined petroleum products is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Rental Revenue. We lease petroleum storage tanks to both related parties and third-parties.  Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement.  Tank rental revenue is recognized on a straight-line basis as earned.

Easement Revenue. Revenue from land easement fees was associated with a Master Easement Agreement between BDPL and FLNG Land II, Inc., a Delaware corporation (“FLNG”).  Easement revenue was recognized monthly as earned and was included in other income.  In February 2017, BDPL sold approximately 15 acres of property located in Brazoria County Texas to FLIQ Common Facilities, LLC, an affiliate of FLNG.  In conjunction with the sale of real estate, the Master Easement Agreement was terminated.

Pipeline Transportation Revenue. Revenue from our pipeline operations was derived from fee-based contracts and was typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue was recognized when volumes were physically delivered for the customer through the pipeline.  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.  (See “Note (4) Business Segment Information” for further discussion related to pipeline transportation revenue.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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 the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.  A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2016. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2016.

FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.  (See “Note (15) 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.

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 it is 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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations.  Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.  (See “Note (11) 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 (16) Earnings Per Share” for additional information related to EPS.)

Treasury Stock. We accounted for treasury stock under the cost method.  In May 2017, our treasury stock was re-issued.  The net change in share price after acquisition of the treasury stock was recognized as a component of additional paid-in-capital in our consolidated balance sheets.  (See “Note (12) Treasury Stock” for additional disclosures related to treasury stock.)

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

ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (A Consensus of the FASB Emerging Issues Task Force). In November 2016, FASB issued ASU 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. We adopted this accounting pronouncement effective December 31, 2016. Accordingly, our consolidated statement of cash flows for the nine months ended September 30, 2016 was changed to combine restricted cash with cash and cash equivalents.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11, which requires an entity to measure inventory at the lower of cost or net realizable value.  We adopted this accounting pronouncement effective January 1, 2017.  The adoption of ASU 2015-11 did not have a significant impact on our consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.  In January 2017, FASB issued ASU 2017-04.  This guidance simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test.  For public business entities that are SEC filers, the amendments in ASU 2017-04 are effective for the annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019.  ASU 2017-04 should be applied prospectively, and early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.  We do not expect adoption of this guidance to have a significant impact on our consolidated balance sheets.

ASU 2016-02,Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2014-09, Revenue from Contracts with Customers.  In May 2014, FASB issued ASU 2014-09 and has since amended the standard with ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date;ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net);ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing; ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update); ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients; and ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.  These standards replace existing revenue recognition rules with a single comprehensive model to use in accounting for revenue arising from contracts with customers.  We are evaluating the impact that adoption of these ASU’s will have 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.

Reclassification.  Effective January 1, 2017, we reclassified amounts associated with our Pipeline Transportation operations to Corporate and Other.  (See “Note (4) Business Segment Information” for disclosures related to Corporate and Other.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

(4) Business Segment Information

Effective January 1, 2017, we began reporting as a single business segment – Refinery Operations.  Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility.  Due to their small size, current and prior three and nine months’ amounts associated with Pipeline Transportation operations were reclassified to Corporate and Other. Pipeline Transportation operations diminished significantly as services to third-parties ceased and third-party wells along our pipeline corridor were permanently abandoned.  Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Three Months Ended September 30,
	2017			2016
	Segment			Segment
	Refinery	Corporate &		Refinery	Corporate &
	Operations	Other	Total	Operations	Other	Total
Revenue from operations	$66,899,092	$-	$66,899,092	$54,668,780	$19,526	$54,688,306
Less: cost of operations(1)	(61,456,546)	(466,912)	(61,923,458)	(55,495,575)	(367,915)	(55,863,490)
Other non-interest income(2)	-	-	-	-	156,396	156,396
Less: JMA Profit Share(3)	-	-	-	(965,627)	-	(965,627)
EBITDA(4)	$5,442,546	$(466,912)		$(1,792,422)	$(191,993)
Depletion, depreciation and
amortization			(455,437)			(504,719)
Interest expense, net			(574,678)			(484,215)
Income (loss) before income taxes			3,945,519			(2,973,349)
Income tax benefit			-			1,034,798
Net income (loss)			$3,945,519			$(1,938,551)
Capital expenditures	$538,801	$-	$538,801	$4,191,077	$-	$4,191,077
Identifiable assets	$70,791,236	$2,068,269	$72,859,505	$85,585,499	$10,816,664	$96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Note (1) Organization – Going Concern – Final Arbitration Award” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

	Nine Months Ended September 30,
	2017			2016
	Segment			Segment
	Refinery	Corporate &		Refinery	Corporate &
	Operations	Other	Total	Operations	Other	Total
Revenue from operations	$176,841,172	$-	$176,841,172	$128,171,177	$71,865	$128,243,042
Less: cost of operations(1)	(197,706,434)	(1,293,162)	(198,999,596)	(135,452,537)	(1,078,910)	(136,531,447)
Other non-interest income(2)	-	-	-	(392,062)	-	(392,062)
Less: JMA Profit Share(3)	-	2,216,251	2,216,251	-	412,061	412,061
EBITDA(4)	$(20,865,262)	$923,089		$(7,673,422)	$(594,984)
Depletion, depreciation and
amortization			(1,355,780)			(1,415,519)
Interest expense, net			(1,999,760)			(1,301,486)
Loss before income taxes			(23,297,713)			(10,985,411)
Income tax benefit			-			3,735,040
Net loss			$(23,297,713)			$(7,250,371)
Capital expenditures	$3,428,129	$-	$3,428,129	$13,857,434	$-	$13,857,434
Identifiable assets	$70,791,236	$2,068,269	$72,859,505	$85,585,499	$10,816,664	$96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses and the arbitration award and associated fees.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Note (1) Organization – Going Concern – Final Arbitration Award” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

(5) 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,
	2017	2016
Prepaid crude oil and condensate	$1,332,439	$-
Prepaid insurance	298,913	248,853
Short-term tax bond	-	505,000
Prepaid exise taxes	-	292,338
	$1,631,352	$1,046,191

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

(6) Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,	December 31,
	2017	2016
Crude oil and condensate	$1,207,865	$26,123
AGO	910,189	143,362
HOBM	341,660	212,987
Chemicals	156,535	182,751
Naphtha	135,554	533,580
Propane	18,377	11,318
LPG mix	5,260	1,293
Jet fuel	-	964,124
	$2,775,440	$2,075,538

(7) Property, Pland and Equipment, Net

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

	September 30,	December 31,
	2017	2016
Refinery and facilities	$51,432,434	$50,814,309
Land	566,159	602,938
Other property and equipment	652,795	652,795
	52,651,388	52,070,042
Less:  Accumulated depletion, depreciation, and amortization	(8,041,024)	(6,685,244)
	44,610,364	45,384,798
Construction in progress	19,786,447	16,939,665
	$64,396,811	$62,324,463

We capitalize interest cost incurred on funds used to construct property, plant, and equipment.  The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life.  Interest cost capitalized was $3,413,428 and $2,108,298 at September 30, 2017 and December 31, 2016, respectively.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

(8) Related Party Transactions

We are party to several agreements with related parties.  We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions.

Related Parties.

LEH.  LEH is our controlling shareholder.  Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH.  Together LEH and Jonathan Carroll own approximately 81% of our Common Stock.  We are currently party to an Amended and Restated Operating Agreement, a Jet Fuel Sales Agreement, a Loan and Security Agreement, an Amended and Restated Promissory Note, and a Debt Assumption Agreement with LEH.

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

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

Jonathan Carroll.  Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin.  We are currently party to Amended and Restated Guaranty Fee Agreements and an Amended and Restated Promissory Note with Jonathan Carroll.

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.  Each quarter amounts we owe to related parties are settled with amounts owed to us by LEH and its affiliates under certain related-party agreements as discussed within this Note (8), Related Party Transactions.  As a result, these related-party transactions do not always reflect cash payments between the parties.

Operations Related Agreements.

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

Jet Fuel Sales Agreement.  We sell jet fuel and other products to LEH pursuant to a Jet Fuel Sales Agreement.  LEH resells these products to a government agency.   In support of the Jet Fuel Sales Agreement, we previously leased Nixon Facility petroleum storage tanks to LEH for the storage of the jet fuel under a Terminal Services Agreement (as described below).  The Jet Fuel Sales Agreement terminates on the earliest to occur of: (a) a one-year term expiring March 31, 2018 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 refined petroleum product sales in our consolidated statements of operations.

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

20

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

Tolling Agreement.  In May 2016, we entered a Tolling Agreement with LMT to facilitate loading and unloading of our petroleum products by barge at LMT’s dock facility in Ingleside, Texas.  The Tolling Agreement has a five-year term and may be terminated at any time by the agreement of both parties.  We pay LMT a flat monthly reservation fee of $50,400.  The monthly reservation fee includes tolling volumes up to 84,000 gallons per day.  Tolling volumes totaling more than 210,000 gallons per quarter are billed to us at $0.02 per gallon.  Amounts expensed as tolling fees to LMT under the Tolling Agreement are reflected in cost of refined products sold in our consolidated statements of operations.

Financial Agreements.

Loan and Security Agreement.  In August 2016, BDPL entered a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “LEH Loan Agreement”).  The LEH Loan Agreement matures in August 2018, and accrues interest at rate of 16.00%.  Under the LEH Loan Agreement, BDPL makes a payment to LEH of $500,000 per year.  A final balloon payment is due at maturity.

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

Promissory Notes.  We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements.  The below promissory notes represent advances to fund our working capital requirements. There can be no assurance that LEH and its affiliates will continue to fund our working capital requirements.

●

June LEH Note – In March 2017, Blue Dolphin entered a promissory note with LEH in the original principal amount of $440,815 (the “March LEH Note”).  In June 2017, the March LEH Note was amended and restated to increase the amount by $2,043,482 (the “June LEH Note”).  Interest under the June LEH Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  The June LEH Note has a maturity date of January 2019.  Under the June LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to LEH under the June LEH Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.  At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to LEH under the June LEH Note and a previous promissory note, respectively, was $0. The balances under the notes were settled with amounts owed to us by LEH.

●

March Ingleside Note – In March 2017, a promissory note between Blue Dolphin and Ingleside was amended and restated (the “March Ingleside Note”) to increase the principal amount by $473,445 and extend the maturity date to January 2019. Interest under the March Ingleside Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  Under the March Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to Ingleside under the March Ingleside Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets. At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to Ingleside under the March Ingleside Note was $1,168,748 and $722,278, respectively.

21

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

●

March Carroll Note – In March 2017, a promissory note between Blue Dolphin and Jonathan Carroll was amended and restated (the “March Carroll Note”) to increase the principal amount by $183,030, revise the payment terms to reflect payment in cash and shares of Blue Dolphin Common Stock, and extend the maturity date to January 2019.  Interest under the March Carroll Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  Under the March Carroll Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to Jonathan Carroll under the March Carroll Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets. At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to Jonathan Carroll under the March Carroll Note was $282,907 and $592,412, respectively.

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered into on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Amended and Restated Guaranty Fee Agreements.  Pursuant to Amended and Restated Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt.  Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain loan agreements.  Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets.  Amounts expensed related to Amended and Restated Guarantee Fee Agreements are reflected within interest and other expense in our consolidated statements of operations.  (See “Note (10) Long-Term Debt, Net” for further discussion related to these guaranty fee agreements.)

Financial Statements Impact.

Consolidated Balance Sheets.  Accounts payable, related party to LMT associated with the Tolling Agreement was $823,200 and $369,600 at September 30, 2017 and December 31, 2016, respectively.  Long-term debt, related party associated with the LEH Loan Agreement, June LEH Note, March Ingleside Note, and March Carroll Note as of the dates indicated was as follows:

	September 30,	December 31,
	2017	2016
LEH	$4,000,000	$4,000,000
Ingleside	1,168,748	722,278
Jonathan Carroll	282,907	592,412
	5,451,655	5,314,690
Less: Long-term debt, related party,
current portion	(4,000,000)	(500,000)
	$1,451,655	$4,814,690

Accrued interest associated with the LEH Loan Agreement was $728,889 and $243,556 at September 30, 2017 and December 31, 2016, respectively.

Consolidated Statements of Operations.  Related party revenue from LEH associated with:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Jet fuel sales	$20,802,789	$14,536,997	$56,360,756	$23,449,071
Jet fuel storage fees	56,386	426,000	675,000	750,000
HOBM sales	-	-	3,425,455	-
	$20,859,175	$14,962,997	$60,461,211	$24,199,071

22

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

Related party cost of goods sold associated with the Tolling Agreement with LMT totaled $151,200 and $0 for the three months ended September 30, 2017 and 2016; related party cost of goods sold for the nine months ended September 30, 2017 and 2016 totaled $453,600 and $0.

Related party refinery operating expenses associated with the Amended and Restated Operating Agreement with LEH and the Amended and Restated Tank Lease Agreement with Ingleside for the periods indicated were as follows:

	Three Months Ended September 30,
	2017		2016
	Amount	Per bbl	Amount	Per bbl
LEH	$1,758,005	$1.53	$3,028,646	$2.66
Ingleside	-	-	125,000	0.11
	$1,758,005	$1.53	$3,153,646	$2.77

	Nine Months Ended September 30,
	2017		2016
	Amount	Per bbl	Amount	Per bbl
LEH	$6,222,771	$1.93	$8,618,409	$2.84
Ingleside	-	-	850,000	0.28
	$6,222,771	$1.93	$9,468,409	$3.12

For the three months ended September 30, 2017, refinery operating expenses per bbl decreased compared to the three months ended September 30, 2016 due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement. The Amended and Restated Operating Agreement was effective in April 2017.

For the nine months ended September 2017, refinery operating expenses per bbl decreased compared to the nine months ended September 30, 2017 due to the revised cost-plus expense reimbursement structure as noted above.  In addition, refinery operating expenses per bbl were higher during the nine months ended September 30, 2016 due to significant refinery downtime.

Interest expense associated with the LEH Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
LEH	$201,361	$80,000	$643,046	$80,000
Jonathan Carroll	165,089	172,300	499,184	522,931
	$366,450	$252,300	$1,142,230	$602,931

23

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

(9) 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,
	2017	2016
Unearned revenue	$708,567	$408,770
Board of director fees payable	203,929	136,429
Customer deposits	109,029	450,000
Property taxes	99,236	4,694
Excise and income taxes payable	60,692	24,187
Other payable	38,621	189,719
Insurance	-	67,783
	$1,220,074	$1,281,582

(10) Long-Term Debt, Net

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

	September 30,	December 31,
	2017	2016
First Term Loan Due 2034 (in default)	$23,382,570	$23,924,607
Second Term Loan Due 2034 (in default)	9,553,728	9,729,853
Notre Dame Debt	4,977,953	1,300,000
Term Loan Due 2017	-	184,994
Capital Leases	8,427	135,879
	$37,922,678	$35,275,333
Less: Current portion of long-term debt, net	(35,756,045)	(31,712,336)
Less: Unamortized debt issue costs	(2,166,633)	(2,262,997)
	$-	$1,300,000

24

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

	September 30,	December 31,
	2017	2016
First Term Loan Due 2034 (in default)	$1,673,545	$1,673,545
Second Term Loan Due 2034 (in default)	767,673	767,673
Less: Accumulated amortization	(274,585)	(178,221)
	$2,166,633	$2,262,997

Amortization expense associated with long-term debt, net, which is included in interest expense, was $32,121 and $32,121 for the three months ended September 30, 2017 and 2016, respectively.  Amortization expense was $96,363 and $96,364 for the nine months ended September 30, 2017 and 2016, respectively.

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

	June 30,	December 31,
	2017	2016
Notre Dame Debt	$1,846,964	$1,691,383
LEH Loan Agreement (related party)	728,889	243,556
Second Term Loan Due 2034 (in default)	47,635	44,984
First Term Loan Due 2034 (in default)	35,875	33,866
Capital Leases	423	1,165
Term Loan Due 2017	-	185
	2,659,786	2,015,139
Less:  Interest payable, current portion	(2,659,786)	(323,756)
Long-term interest payable, net of current portion	$-	$1,691,383

Related Party.  See “Note (8) Related Party Transactions” for additional disclosures with respect to related party long-term debt.

First Term Loan Due 2034 (In Default). LE has a 2015 loan agreement and related security agreementwith Veritex as administrative agent and lender.  The loan agreement is for a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”).  The First Term Loan Due 2034 matures in June 2034, has a current monthly payment of principal and interest of $198,786, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

25

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

As described elsewhere in this Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the first Term Loan Due 2034.  LE also failed to replenish a payment reserve account as required.  The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 in light of the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement.  Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.  (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LE entered a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the First Term Loan Due 2034.  Effective in April 2017, the Guaranty Fee Agreement associated with the First Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  For the three months ended September 30, 2017 and 2016, guaranty fees related to the First Term Loan Due 2034 totaled $117,214 and $121,048, respectively. For the nine months ended September 30, 2017 and 2016, guaranty fees related to the First Term Loan Due 2034 totaled $354,286 and $365,420, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.  LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034.  (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll)

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

Second Term Loan Due 2034 (In Default). LRM has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender.  The loan agreement is for a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”).  The Second Term Loan Due 2034 matures in December 2034, has a current monthly payment of principal and interest of $74,111, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As described elsewhere in this Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LRM was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the Second Term Loan Due 2034.  The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement.  Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

26

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034.  Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  For the three months ended September 30, 2017 and 2016, guaranty fees related to the Second Term Loan Due 2034 totaled $47,874 and $49,094, respectively.  For the nine months ended September 30, 2017 and 2016, guaranty fees related to the Second Term Loan Due 2034 totaled $144,487 and $148,261, respectively.  Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.   LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034.  (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

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

Notre Dame Debt. LE entered a loan with Notre Dame Investors, Inc. as evidenced by a promissory note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt matures in January 2018, and accrues interest at a rate of 16.00%.

Pursuant to a Sixth Amendment to the Notre Dame Debt, entered into on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended to increase the principal amount by $3,677,953 (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 $3,648,742 in accordance with the GEL Letter Agreement.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt.  Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Veritex as holder of the First Term Loan Due 2034.

27

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

Term Loan Due 2017. LRM had a 2014 loan and security agreement with Veritex for a term loan facility in the principal amount of $2.0 million (the “Term Loan Due 2017”).  The Term Loan Due 2017 was amended in March 2015, pursuant to a Loan Modification Agreement (the “March Loan Modification Agreement”).  Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due date was extended to March 2017.  Pursuant to the March Loan Modification Agreement, the Term Loan Due 2017 had a monthly principal payment of $61,665 plus interest. The Term Loan Due 2017 was paid off in March 2017.

As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he received a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Term Loan Due 2017.  Effective in April 2017, the Guaranty Fee Agreement associated with the Term Loan Due 2017 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  (Guaranty Fee Agreements associated with the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017 are collectively referred to in this Quarterly Report as the “Amended and Restated Guaranty Fee Agreements”).  For the three months ended September 30, 2017 and 2016, guaranty fees related to the Term Loan Due 2017 totaled $0 and $2,158, respectively. For the nine months ended September 30, 2017 and 2016, guaranty fees related to the Term Loan Due 2017 totaled $411 and $9,250, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

Capital Leases. LRM entered a 36-month build-to-suit capital lease in August 2014 for the purchase of new boiler equipment for the Nixon Facility.  The equipment, which was delivered in December 2014, was added to construction in progress.  Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease, which requires a quarterly payment in the amount of $44,258, is guaranteed by Blue Dolphin.

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

	September 30,	December 31,
	2017	2016
Boiler equipment	$538,598	$538,598
Less:  accumulated depreciation	-	-
	$538,598	$538,598

(11) Asset Retirement Obligations

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

Pipelines and Facilities and Oil and Gas Properties.  We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We depreciate the amount added to property and equipment and recognize accretion expense relating to the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

28

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

	September 30,	December 31,
	2017	2016
Asset retirement obligations, at the beginning of the period	$2,027,639	$1,985,864
Liabilities settled	(445)	(70,969)
Accretion expense	215,532	112,744
	2,242,726	2,027,639
Less:  asset retirement obligations, current portion	(17,065)	(17,510)
Long-term asset retirement obligations, at the end of the period	$2,225,661	$2,010,129

Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability.  At September 30, 2017 and December 31, 2016, we recognized $445 and $70,969, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability.  For the three and nine months ended September 30, 2017 and 2016, we recognized $0 in abandonment expense.

(12) Treasury Stock

At September 30, 2017 and December 31, 2016, we had 0 and 150,000 shares of treasury stock, respectively.  In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which reperesents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements.  The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

(13) 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, 2017 and December 31, 2016, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $1,183,652 and $5,372,689, respectively.

Key Supplier.

We purchased light crude oil and condensate for the Nixon Facility from GEL pursuant to the Crude Supply Agreement.  As discussed elsewhere in this Quarterly Report, we ceased purchases of crude oil and condensate from GEL under the Crude Supply Agreement in November 2016.  (See “Part I, Item 1 Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” in this Quarterly Report for disclosures related to the Crude Supply Agreement, the contract-related dispute with GEL, and the Final Arbitration Award.)

We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company.  This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.  The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts and crude oil and condensate from our current supplier or otherwise.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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, 2017, we had 4 customers that accounted for approximately 84% 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, 2017, these 4 customers represented approximately $1.5 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

For the three months ended September 30, 2016, we had 4 customers that accounted for approximately 70% of our refined petroleum product sales. LEH was one of these 4 significant customers and accounted for approximately 27% of our refined petroleum product sales.  At September 30, 2016, these 4 customers represented approximately $6.7 million in accounts receivable.  LEH represented approximately $2.9 million in accounts receivable.

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

For the nine months ended September 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum product sales.  LEH was one of these 4 significant customers and accounted for approximately 19% of our refined petroleum product sales. At September 30, 2016, these 4 customers represented approximately $5.5 in accounts receivable.  LEH represented approximately $2.9 million in accounts receivable.

LEH purchases our jet fuel and resells the jet fuel to a government agency.  (See “Note (8) Related Party Transactions” for additional disclosures related to our sale of jet fuel to LEH under the Jet Fuel Sales Agreement and the associated storage of LEH’s purchased jet fuel under the Terminal Services Agreement.)

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 began exporting some of our low-sulfur diesel to Mexico during the second quarter of 2016.  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,
	2017		2016		2017		2016
LPG mix	$-	0.0%	$237,009	0.4%	$120,542	0.1%	$621,313	0.5%
Naphtha	14,266,056	21.6%	11,870,484	22.0%	41,282,969	24.9%	28,183,809	22.3%
Jet fuel	20,802,789	31.5%	15,104,900	28.0%	56,360,757	32.8%	41,150,686	32.5%
HOBM	17,011,443	25.7%	14,206,759	26.4%	38,580,236	19.9%	25,259,753	20.0%
Reduced Crude	-	0.0%	-	0.0%	-	0.0%	3,791,919	3.0%
AGO	14,052,671	21.2%	12,532,141	23.2%	38,323,113	22.3%	27,539,236	21.7%
	$66,132,959	100.0%	$53,951,293	100.0%	$174,667,617	100.0%	$126,546,716	100.0%

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

(14) Leases

Our company headquarters are in downtown Houston, Texas.  We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease had a 10-year term expiring in September 2017, but we extended the lease through December 2017.  We are currently exploring our leasing options. Rent expense is recognized on a straight-line basis.  For the three months ended September 30, 2017 and 2016, rent expense totaled $31,681 and $33,251, respectively.  For the nine months ended September 30, 2017 and 2016, rent expense totaled $107,853 and $92,966, respectively.

(15) Income Taxes

Income Tax Benefit.  For the three months ended September 30, 2017 and 2016, we recognized an income tax benefit of $0 and $1,034,798 respectively. For the nine months ended September 30, 2017 and 2016, we recognized an income tax benefit of $0 and $3,735,040, respectively.

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 Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, relating to a series of private placements, and in 2012, because of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income.  In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of $638,196 per year.  Unused portions of the annual use limitation amount may be used in subsequent years.  As a result of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused.  NOL carryforwards that were generated after the 2012 ownership change are not subject to an annual use limitation under IRC Section 382 and may be used for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change.

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

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

	Net Operating Loss Carryforward
	Pre-Ownership Change	Post-Ownership Change	Total
Balance at December 31, 2015	$9,614,449	$9,616,941	$19,231,390
Net operating losses	-	13,945,128	13,945,128
Balance at December 31, 2016	$9,614,449	$23,562,069	$33,176,518
Net operating losses	-	6,469,611	6,469,611
Balance at September 30, 2017	$9,614,449	$30,031,680	$39,646,129

Deferred Tax Assets and Liabilities.  At September 30, 2017 and December 31, 2016, we had $0 of net deferred tax assets available for future use.  Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:

	September 30,	December 31,
	2017	2016
Deferred tax assets:
Net operating loss and capital loss carryforwards	$15,750,006	$13,550,338
Accrued arbitration award payable	6,674,017	-
Start-up costs (Nixon Facility)	1,270,361	1,373,363
Asset retirement obligations liability/deferred revenue	780,249	717,751
AMT credit and other	224,647	266,522
Total deferred tax assets	24,699,280	15,907,974
Deferred tax liabilities:
Basis differences in property and equipment	(6,762,850)	(5,895,943)
Total deferred tax liabilities	(6,762,850)	(5,895,943)
	17,936,430	10,012,031
Valuation allowance	(17,936,430)	(10,012,031)
Deferred tax assets, net	$-	$-

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, 2017 and December 31, 2016, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of September 30, 2017 and December 31, 2016.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

Uncertain Tax Positions. We adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2013, or after and by the state of Texas for tax years ending December 31, 2012, or after.  We believe there are no uncertain tax positions for both federal and state income taxes.

(16) 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,
	2017	2016	2017	2016
Net income (loss)	$3,945,519	$(1,938,551)	$(23,297,713)	$(7,250,371)
Basic and diluted income per share	$0.36	$(0.19)	$(2.19)	$(0.69)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,818,371	10,464,715	10,644,654	10,460,849

Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three and nine months ended September 30, 2017 and 2016 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

(17) Inventory Risk Management

During 2017, we began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure.  Previously, Genesis/GEL used commodity futures contracts to mitigate the volatile change in value for our crude oil and refined petroleum products inventory.

When active, the fair value of commodity futures contracts was reflected in our consolidated balance sheets and the related net gain or loss was recorded within cost of refined products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) were considered to determine the fair values for marking to market the financial instruments at each period end.  Commodity transactions were executed to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors.

At September 30, 2017, we had no futures contracts of refined petroleum products and crude oil and condensate that were entered as economic hedges.  We also had no derivative instruments that were reported in our consolidated balance sheets at September 30, 2017 and December 31, 2016.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016: 

		Gain (Loss) Recognized
		Three Months Ended September 30,		Nine Months Ended September 30,
Derivatives	Statements of Operations Location	2017	2016	2017	2016
Commodity contracts	Cost of refined products sold	$-	$770,838	$-	$(2,588,734)

(18) Commitments and Contingencies

 

Legal Matters.

GEL Contract-Related Dispute and Final Arbitration Award. See “Note (1) Organization – Going Concern – Final Arbitration Award” of this Quarterly Report for disclosures related to the GEL contract-related dispute and Final Arbitration Award. In addition, see "Part II, Item 1. Legal Proceedings” in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017 as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding the contract related dispute and Final Arbitration Award.

Veritex Secured Loan Agreement Event of Default. See “Note (1) Organization – Going Concern – Veritex Secured Loan Agreement Event of Default” and “Note (10) Long-Term Debt, Net” for disclosures related to defaults under secured loan agreements.

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

Amended and Restated Operating Agreement. See “Note (8) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.

Financing Agreements. See “Note (10) Long-Term Debt, Net” for additional disclosures related to financing agreements.

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

Nixon Facility Expansion. Wehave made and continue to make capital and efficiency improvements to the Nixon Facility. Therefore, we incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and completion of petroleum storage tanks.

Supplemental Pipeline Bonds. In August 2015, we received a letter from the Bureau of Ocean Energy Management (the “BOEM”) requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In July 2016, the BOEM issued Notice to Lessees (“NTL”) No. 2016-N01 (Requiring Additional Security), which changes the way that lessees and rights-of-way holders demonstrate financial strength and reliability to plug and abandon wells, as well as decommission and remove platforms and pipelines at the end of production or service activities. The NTL, which changed an earlier supplemental waiver process to a self-insurance model, became effective in September 2016. Pursuant to the NTL, the BOEM requested that lessees submit any relevant information needed for an overall financial review of the lessees account.  The BOEM indicated that it would use this information to evaluate a lessees’ ability to carry out its obligations and determine whether, and/or how much self-insurance a lessee can use.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Notes to Consolidated Financial Statements (Continued)

In October 2016, we received a letter from the BOEM summarizing the amount required as additional security on our existing pipeline rights-of-way.  The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental pipeline bonds or acceptable financial reassurance of approximately $4.6 million.  At September 30, 2017 and December 31, 2016, we maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM.  Of the five (5) pipeline rights-of-ways reflected in the BOEM’s October 2016 letter:

(i)  

the pipeline associated with one (1) right-of-way was decommissioned in 1997, and

(ii)  

the pipelines associated with three (3) rights-of-way (Segment Nos. 15635, 13101, and 9428) have been approved for decommissioning by the Bureau of Safety and Environmental Enforcement (the “BSEE”); decommissioning of Segment No. 9428 also requires approval by the U.S. Army Corps of Engineers, which has not yet been granted.

There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way.  If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

(19) Subsequent Events

Amended GEL Letter Agreement.  As previously disclosed, on November 1, 2017, LE and GEL extended the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017.  For additional information regarding the Final Arbitration Award, the GEL Letter Agreement, the Amended GEL Letter Agreement, and their potential effects on our business, financial condition and results of operations, see “Note (1) Organization – Going Concern” and “Note (10) Long-Term Debt, Net.”

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered into on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Sixth Amendment to Notre Dame Debt. Pursuant to a Sixth Amendment to the Notre Dame Debt, entered into on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended by the Additional Principal. The Additional Principal was used to make payments to GEL in the amount of $3,648,742 in connection with the GEL Letter Agreement to reduce the balance of the Final Arbitration Award.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

 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, 2017 (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 period ended March 31, 2017 and June 30, 2017, as well as our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (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

●

Failure to reach a settlement agreement with GEL (See “GEL Contract-Related Dispute and Final Arbitration Award” below).

●

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

●

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

●

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

●

Competition from companies having greater financial and other resources.

●

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

●

Insurance coverage that may be inadequate or expensive.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

●

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

●

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

●

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

●

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

Risks Related to Our Refinery Operations Business Segment

●

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

●

Volatility of refining margins.

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Risks Related to Our Pipelines and Oil and Gas Properties

●

Required increases in bonds or other sureties to maintain compliance with regulatory requirements, which could significantly impact our liquidity and financial condition.

●

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

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

GEL Contract-Related Dispute and Final Arbitration Award

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 the 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 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, legal and administrative fees and court costs to GEL in the aggregate amount of approximately $31.3 million.

A hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for the Continuance Period to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into the GEL Letter Agreement, confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement.

GEL could have terminated the GEL Letter Agreement on the 45th day of the Continuance Period, or November 1, 2017, if GEL determined, in its sole discretion, that settlement discussions between the parties were not advancing to an acceptable resolution.  As previously disclosed, on November 1, 2017, LE and GEL amended the GEL Letter Agreement to extend the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017.  The Amended GEL Letter Agreement prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period.  If we are unable to reach an acceptable settlement with Genesis and GEL and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially affected, and we likely would be required to seek protection under bankruptcy laws.

Veritex Community Bank, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating the that the Final Arbitration Award constitutes an event of default under the secured loan agreements.  The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under these loan agreements, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.  The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential 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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

In addition to the matters described in the previous paragraphs, the Final Arbitration Award could materially and adversely affect our ability to procure adequate amounts of crude oil and condensate and our relationships with our customers.

Company Overview

Blue Dolphin is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000-bpd crude oil and condensate processing facility that is in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own pipeline assets and have leasehold interests in oil and gas wells.  The pipelines and oil and gas wells are inactive.  We maintain a website at http://www.blue-dolphin-energy.com.  Information on or accessible through our website is not incorporated by reference in or otherwise made a part of this Quarterly Report.

Major Influences on Results of Operations

As a margin-based business, our refinery operations are primarily affected by the per bbl price differential between crude oil and condensate and refined petroleum products, our product slate, and refinery downtime.

Feedstock and Product per Bbl Price Differentials

The prices of crude oil and refined petroleum products are the most significant driver of margins, and they have historically been subject to wide fluctuations. Our cost to acquire crude oil and condensate and the 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.

For the Current Three Months, the average per bbl price differential between crude oil and condensate and refined petroleum products was $6.46 compared to $2.01 for the three months ended September 30, 2016 (the “Prior Three Months”), reflecting an increase of $4.45.  Our gross profit increased from $2,998,832 in the Prior Three Months to $8,113,265 in the Current Three Months, reflecting an increase of $5,114,433.  The increase between the periods was primarily because of improved margins on refined petroleum products.

39

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

For the nine months ended September 30, 2017 (the “Current Nine Months”), the average per bbl price differential between crude oil and condensate and refined petroleum products was $3.02 compared to $0.42 for the nine months ended September 30, 2016 (the “Prior Nine Months”), reflecting an increase of $2.60.  Our gross profit increased from $2,926,793 in the Prior Nine Months to $11,655,896 in the Current Nine Months, reflecting an increase of $8,729,103.  The increase between the periods was primarily because of improved margins on refined petroleum products.

Product Slate

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

Refinery Downtime

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

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

Key Relationships

Relationship with LEH

We are currently party to a variety of agreements with LEH, including an Amended and Restated Operating Agreement, a Jet Fuel Sales Agreement, a Loan and Security Agreement, an Amended and Restated Promissory Note, and a Debt Assumption Agreement.  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 (8) Related Party Transactions” for disclosures related to agreements that we have in place with LEH.)

Relationship with Crude Supplier

Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate on favorable terms.  We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company.  This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.  Management believes that it is taking the appropriate steps to improve our financial stability.  However, there can be no assurance that our plan will be successful, LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all.  Among other factors, the Final Arbitration Award could prevent us from successfully executing our plan. If our plan is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under the existing contract or otherwise.  Further, because our existing crude supply contract is a month-to-month arrangement, there can be no assurance that crude oil and condensate supplies will continue to be available under this contract in the future.

40

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Results of Operations

Effective January 1, 2017, we began reporting a single business segment – Refinery Operations.  Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility.  Due to their small size, amounts associated with Pipeline Transportation operations for the Current Three Months and Current Nine Months were reclassified to Corporate and Other. Pipeline Transportation operations diminished significantly as services to third-parties ceased and third-party wells along our pipeline corridor were permanently abandoned.

In this Results of Operations section, we review:

●

Definitions of key financial performance measures used by management;

●

Consolidated results (reflect financial results for our Refinery Operations business segment and Corporate and Other);

●

Non-GAAP financial measures; and

●

Refinery Operations business segment results.

Remainder of Page Intentionally Left Blank

41

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

GLOSSARY OF SELECTED FINANCIAL AND PERFORMANCE MEASURES

Management uses 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. Below are definitions of key financial performance measures used by management:

Adjusted Earnings Before Interest, Income Taxes and Depreciation (“EBITDA”).  Reflects EBITDA excluding the JMA Profit Share.

-  

Refinery Operations Adjusted EBITDA. Reflects adjusted EBITDA for our refinery operations business segment.

-  

Total Adjusted EBITDA. Reflects adjusted EBITDA for our refinery operations business segment, as well as corporate and other.

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 Nixon Facility, the rate is calculated by dividing total refinery throughput or total refinery production on a bpd basis by the total capacity of the Nixon Facility (currently 15,000 bpd).

Cost of Refined Products Sold. Primarily includes purchased crude oil and condensate costs, as well as transportation, freight and storage costs.

Depletion, Depreciation and Amortization. Represents property and equipment, as well as intangible assets that are depreciated or amortized based on the straight-line method over the estimated useful life of the related asset.

Downtime. Scheduled and/or unscheduled periods in which the Nixon Facility is not operating.  Downtime may occur for a variety of reasons, including bad weather, power failures, preventive maintenance, equipment inspection, equipment repair due to mechanical failure, voluntary regulatory compliance measures, cessation or suspension by regulatory authorities, and inventory management.

Easement, Interest and Other Income. Reflects land easement fees received from FLNG Land II, Inc., a Delaware corporation (“FLNG”), pursuant to a Master Easement Agreement; fees recognized monthly as earned and recorded as land easement revenue within other income.

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

-  

Refinery Operations EBITDA. Reflects EBITDA for our refinery operations business segment.

-  

Total EBITDA. Reflects EBITDA for our refinery operations business segment, as well as corporate and other.

General and Administrative Expenses. Primarily include corporate costs, such as accounting and legal fees, office lease expenses, and administrative expenses.

Gross Profit.Calculated as total revenue less cost of refined products sold.

Income Tax Expense. Includes federal and state taxes, as well as deferred taxes, arising from temporary differences between income for financial reporting and income tax purposes.

JMA Profit Share. Represents the GEL Profit Share plus the Performance Fee for the period under the Joint Marketing Agreement; an indirect operating expense. If Gross Profits were positive, then the JMA Profit Share reflected an expense.  If Gross Profits were negative, then the JMA Profit Share reflected a credit.

Net Income. Represents total revenue from operations less total cost of operations, total other expense, and income tax expense.

Operating Days. Represents the number of days in a period in which the Nixon Facility operated. Operating days is calculated by subtracting downtime in a period from calendar days in the same period.

Other Income (Expense).  Reflects working capital loan interest, guaranty fees paid to Jonathan Carroll, expensed interest related to long-term debt, and non-recurring income items.

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

Refinery Operating Expenses. Direct operating expenses of the Nixon Facility, including direct costs of labor, maintenance materials and services, chemicals and catalysts and utilities.  Includes fees paid to: (i) LEH to manage and operate the Nixon Facility pursuant to the Amended and Restated Operating Agreement and (ii) Ingleside Crude, LLC to lease petroleum storage tanks to meet periodic, additional storage needs under the Amended and Restated Tank Lease Agreement.

Revenue from Operations. Primarily consists of refined petroleum product sales, but also includes tank rental revenue. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.  Other revenue relates to fees received from pipeline transportation services, which ceased in 2016.

Total Refinery Production. Refers to the volume processed as output through the Nixon Facility. Refinery production includes finished petroleum products, such as jet fuel and exportable low-sulfur diesel, and intermediate petroleum products, such as LPG, naphtha, HOBM and AGO.

Total Refinery Throughput. Refers to the volume processed as input through the Nixon Facility.  Refinery throughput includes crude oil and condensate and other feedstocks.

42

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Consolidated Results

Current Three Months Compared to Prior Three Months.

Total Revenue from Operations. For the Current Three Months, we had total revenue from operations of $66,899,092 compared to total revenue from operations of $54,688,306 for the Prior Three Months.  The approximate 22% increase in total revenue from operations between the periods was primarily the result of higher commodity prices for refined petroleum products in the Current Three Months compared to the Prior Three Months.

Cost of Refined Products Sold. Cost of refined products sold was $58,785,827 for the Current Three Months compared to $51,689,474 for the Prior Three Months.  The approximate 14% increase in cost of refined products sold was primarily the result of higher crude oil prices in the Current Three Months compared to the Prior Three Months.

Gross Profit. For the Current Three Months, gross profit totaled $8,113,265 compared to gross profit of $2,998,832 for the Prior Three Months.  The $5,114,433 increase between the periods related to higher commodity prices for refined petroleum products in the Current Three Months compared to the Prior Three Months.

Refinery Operating Expenses.  We recorded refinery operating expenses of $1,758,005 in the Current Three Months compared to $3,153,646 in the Prior Three Months, a decrease of 44%.  Refinery operating expenses per bbl of throughput were $1.53 in the Current Three Months compared to $2.77 in the Prior Three Months.  The $1.24 decrease in refinery operating expenses per bbl of throughput between the periods was the result of: (i) significantly lower refinery operating expenses under the Amended and Restated Operating Agreement, which was restructured following cessation of crude supply and marketing activities under the Crude Supply Agreement and Joint Marketing Agreement with GEL and (ii) a decrease in off-site tank leasing expense under an Amended and Restated Tank Lease Agreement. (See “Part I, Item 1. Financial Statements – Note (8) Related Party Transactions” for additional disclosures related to components of refinery operating expenses, the Amended and Restated Operating Agreement, and the Amended and Restated Tank Lease Agreement.)

JMA Profit Share.  For the Current Three Months, the JMA Profit Share was $0 compared to an expense of $965,627 for the Prior Three Months.  Elimination of the JMA Profit Share between the periods was the result of cessation of marketing activities under the Joint Marketing Agreement.  (See “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” for further discussion related to the Joint Marketing Agreement, JMA Profit Share, Gross Profits and the contract-related dispute with GEL.)

General and Administrative Expenses. We incurred general and administrative expenses of $1,239,813 in the Current Three Months compared to $891,210 in the Prior Three Months.  The 39% increase in general and administrative expenses in the Current Three Months compared to the Prior Three Months primarily related to an increase in legal fees associated with the contract-related dispute with GEL.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $455,437 in the Current Three Months compared to $504,719 in the Prior Three Months.  The approximate 10% decrease in depletion, depreciation and amortization expenses for the Current Three Months compared to the Prior Three Months was primarily due to lower depreciation related to our pipeline assets.

Other Income (Expense).  We recorded $574,678 in other expensein the Current Three Months compared to $327,819 in other expense in the Prior Three Months.  The significant increase in other expense between the periods primarily related to a decrease in easement income and an increase in working capital loan interest.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Income Tax Benefit.  We recognized an income tax benefit of $0 in the Current Three Months compared to $1,034,798 in the Prior Three Months.  Income tax benefit in the Prior Three Months primarily related to deferred federal income taxes.  We recorded a full valuation allowance against deferred tax assets as of September 30, 2017 and December 31, 2016 (See “Part I, Item 1. Financial Statements – Note (15) Income Taxes” for additional disclosures related to income taxes.)

Net Income (Loss).  For the Current Three Months, we reported income of $3,945,519, or income of $0.36 per share, compared to a net loss of $1,938,551, or loss of $0.19 per share, for the Prior Three Months. The $0.55 per share improvement between the periods was primarily the result of favorable refining margins.

Current Nine Months Compared to Prior Nine Months.

Total Revenue from Operations. For the Current Nine Months, we had total revenue from operations of $176,841,172 compared to total revenue from operations of $128,243,042 for the Prior Nine Months.  The approximate 38% increase in total revenue from operations between the periods was primarily the result of higher commodity prices for refined petroleum products and a 7% increase in sales volume in the Current Nine Months compared to the Prior Nine Months.  Refinery production increased due to improved refinery uptime.  The Nixon Facility experienced significant downtime for the Prior Nine Months due to the contract-related dispute with GEL.

Cost of Refined Products Sold. Cost of refined products sold was $165,185,276 for the Current Nine Months compared to $125,316,249 for the Prior Nine Months.  The approximate 32% increase in cost of refined products sold was the result of higher commodity prices for crude oil and increased sales volume in the Current Nine Months compared to the Prior Nine Months.

Gross Profit. For the Current Nine Months, gross profit totaled $11,655,896 compared to gross profit of $2,926,793 for the Prior Nine Months.  The $8,729,103 increase between the periods related to favorable refining margins and increased sales volume in the Current Nine Months compared to the Prior Nine Months.

Refinery Operating Expenses.  We recorded refinery operating expenses of $6,222,771 in the Current Nine Months compared to $9,468,409 in the Prior Nine Months, a decrease of approximately 34%.  Refinery operating expenses per bbl of throughput were $1.93 in the Current Nine Months compared to $3.12 in the Prior Nine Months.  The $1.19 decrease in refinery operating expenses per bbl of throughput between the periods was the result of: (i) significantly lower refinery operating expenses under the Amended and Restated Operating Agreement, which was restructured following cessation of crude supply and marketing activities under the Crude Supply Agreement and Joint Marketing Agreement with GEL and (ii) a decrease in off-site tank leasing expense under an Amended and Restated Tank Lease Agreement. (See “Part I, Item 1. Financial Statements – Note (8) Related Party Transactions” for additional disclosures related to components of refinery operating expenses, the Amended and Restated Operating Agreement, and the Amended and Restated Tank Lease Agreement.)

JMA Profit Share.  For the Current Nine Months, the JMA Profit Share was $0 compared to an expense of $392,062 for the Prior Nine Months.  Elimination of the JMA Profit Share between the periods was the result of cessation of marketing activities under the Joint Marketing Agreement.  (See “Part I, Item 1. Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” for further discussion related to the Joint Marketing Agreement, JMA Profit Share, Gross Profits and the contract-related dispute with GEL.)

Arbitration Award and Associated Fees.  For the Current Nine Months, legal settlement and fees totaled $24,338,628 compared to $0 for the Prior Nine Months.  Legal settlement and fees were associated with the Final Arbitration Award.

General and Administrative Expenses. We incurred general and administrative expenses of $2,854,294 in the Current Nine Months compared to $1,503,533 in the Prior Nine Months.  The nearly 90% increase in general and administrative expenses in the Current Nine Months compared to the Prior Nine Months primarily related to an increase in legal fees associated with the contract-related dispute with GEL.

44

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $1,355,780 in the Current Nine Months compared to $1,415,519 in the Prior Nine Months.  The approximate 4% decrease in depletion, depreciation and amortization expenses for the Current Nine Months compared to the Prior Nine Months was primarily due to lower depreciation related to our pipeline assets.

Other Income (Expense).  We recorded $207,149 in other income in the Current Nine Months compared to $889,425 of other expense in the Prior Nine Months.  The improvement in other income between the periods related to a gain on the sale of land to FLNG in the first quarter of 2017, which was offset by interest expense related to working capital loan interest, long-term debt interest expense, and guaranty fee expense.  In February 2017, BDPL sold approximately 15 acres of property located in Brazoria County, Texas to FLIQ Common Facilities, LLC, an affiliate of FLNG.  In conjunction with the sale of real estate, the FLNG Easements were terminated.

Income Tax Benefit.  We recognized an income tax benefit of $0 in the Current Nine Months compared to $3,735,040 in the Prior Nine Months.  Income tax benefit in the Prior Nine Months primarily related to deferred federal income taxes.  We recorded a full valuation allowance against deferred tax assets as of September 30, 2017 and December 31, 2016 (See “Part I, Item 1. Financial Statements – Note (15) Income Taxes” for additional disclosures related to income taxes.)

Net Loss.  For the Current Nine Months, we reported a net loss of $23,307,055, or a loss of $2.19 per share, compared to net loss of $7,250,371, or loss of $0.69 per share, for the Prior Nine Months.  The $1.50 per share increase in net loss between the periods was primarily the result of the Final Arbitration Award in the Current Nine Months compared to the Prior Nine Months.

Remainder of Page Intentionally Left Blank

45

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Non-GAAP Financial Measures

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

EBITDA Current Three Months Compared to Prior Three Months.

Refinery Operations EBITDA.  Refinery operations EBITDA for the Current Three Months was $5,442,546 compared to a loss of $1,792,422 for the Prior Three Months.  The significant increase in refinery operations EBITDA between the periods was primarily the result of improved margins on refined petroleum products in the Current Three Months.

EBITDA Reconciliation to GAAP – Three Month Periods.

	Three Months Ended September 30,
	2017			2016
	Segment			Segment
	Refinery	Corporate &		Refinery	Corporate &
	Operations	Other	Total	Operations	Other	Total
Revenue from operations	$66,899,092	$-	$66,899,092	$54,668,780	$19,526	$54,688,306
Less: cost of operations(1)	(61,456,546)	(466,912)	(61,923,458)	(55,495,575)	(367,915)	(55,863,490)
Other non-interest income(2)	-	-	-	-	156,396	156,396
Less:  JMA Profit Share(3)	-	-	-	(965,627)	-	(965,627)
EBITDA	$5,442,546	$(466,912)	$4,975,634	$(1,792,422)	$(191,993)	$(1,984,415)
Depletion, depreciation and
amortization			(455,437)			(504,719)
Interest expense, net			(574,678)			(484,215)
Income (loss) before income taxes			3,945,519			(2,973,349)
Income tax benefit			-			1,034,798
Net income (loss)			$3,945,519			$(1,938,551)

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern – Final Arbitration Award” for further discussion of the contract-related dispute with GEL.)

46

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

EBITDA Current Nine Months Compared to Prior Nine Months.

Refinery Operations EBITDA.  Refinery operations EBITDA for the Current Nine Months was a loss of $20,865,262 compared to a loss of $7,673,422 for the Prior Nine Months.  The significant decrease in refinery operations EBITDA between the periods was primarily the result of the Final Arbitration Award in the Current Nine Months.

EBITDA Reconciliation to GAAP – Nine Month Periods.

	Nine Months Ended September 30,
	2017			2016
	Segment			Segment
	Refinery	Corporate &		Refinery	Corporate &
	Operations	Other	Total	Operations	Other	Total
Revenue from operations	$176,841,172	$-	$176,841,172	$128,171,177	$71,865	$128,243,042
Less: cost of operations(1)	(197,706,434)	(1,293,162)	(198,999,596)	(135,452,537)	(1,078,910)	(136,531,447)
Other non-interest income(2)	-	2,216,251	2,216,251	-	412,061	412,061
Less:  JMA Profit Share(3)	-	-	-	(392,062)	-	(392,062)
EBITDA	$(20,865,262)	$923,089	$(19,942,173)	$(7,673,422)	$(594,984)	$(8,268,406)
Depletion, depreciation and
amortization			(1,355,780)			(1,415,519)
Interest expense, net			(1,999,760)			(1,301,486)
Loss before income taxes			(23,297,713)			(10,985,411)
Income tax benefit			-			3,735,040
Net loss			$(23,297,713)			$(7,250,371)

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses and the arbitration award and associated fees.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern – Final Arbitration Award” for further discussion of the contract-related dispute with GEL.)

Refinery Operations Business Segment Results

During the Current Three Months, the average per bbl price differential between crude oil and condensate and refined petroleum products was $6.46 compared to $2.01 for the Prior Three Months, reflecting an increase of $4.45.  Our gross profit increased from $2,998,832 in the Prior Three Months to $8,113,265 in the Current Three Months, reflecting an increase of $5,114,433.  The increase between the periods was primarily due to favorable refining margins.

During the Current Nine Months, the average per bbl price differential between crude oil and condensate and refined petroleum products was $3.02 compared to $0.42 for the Prior Nine Months, reflecting an increase of $2.60.  Our gross profit increased from $2,926,793 in the Prior Nine Months to $11,655,896 in the Current Nine Months, reflecting an increase of $8,729,103.  The increase between the periods was primarily due to favorable refining margins and increased sales volume.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refinery Throughput and Production Data.

Following are refinery operational metrics for the Nixon Facility:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Calendar Days	92	92	273	274
Refinery downtime	(3)	(1)	(17)	(30)
Operating Days	89	91	256	244
Total refinery throughput (bbls)	1,145,484	1,139,458	3,228,144	3,034,257
Operating days:
bpd	12,871	12,522	12,610	12,435
Capacity utilization rate	85.8%	83.5%	84.1%	82.9%
Calendar days:
bpd	12,451	12,385	11,825	11,074
Capacity utilization rate	83.0%	82.6%	78.8%	73.8%
Total refinery production (bbls)	1,110,734	1,106,415	3,127,391	2,948,821
Operating days:
bpd	12,480	12,158	12,216	12,085
Capacity utilization rate	83.2%	81.1%	81.4%	80.6%
Calendar days:
bpd	12,073	12,026	11,456	10,762
Capacity utilization rate	80.5%	80.2%	76.4%	71.7%

Note:  The difference between total refinery throughput (volume processed as input) and total refinery production (volume processed as output) represents refinery fuel use and loss.

In the Current Three Months, the Nixon Facility experienced 3 days of refinery downtime related to repairs and Hurricane Harvey.  In the Prior Three Months, the Nixon Facility experienced 1 day of refinery downtime due to maintenance.  Total refinery throughput bbls and total refinery production bbls were flat between the periods.

In the Current Nine Months, the Nixon Facility experienced 17 days of refinery downtime related to throughput management, repairs, and Hurricane Harvey.  In the Prior Nine Months, the Nixon Facility experienced 30 days of refinery downtime primarily due to the contract-related dispute with GEL.  Despite the significant downtime in the Current Nine Months, total refinery throughput bbls and total refinery production bbls increased approximately 6% compared to the Prior Nine Months because of improved refinery uptime associated with crude oil and condensate delivery.

Refined Petroleum Product Sales Summary.

(See “Part I, Item 1. Financial Statements - Note (13) Concentration of Risk” for a discussion of refined petroleum product sales.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refined Petroleum Products Economic Hedges.

During 2017, we began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk.  Previously, Genesis/GEL used commodity futures contracts to mitigate the volatile change in value for certain of our refined petroleum products inventory.

We had no open commodity contracts in the Current Three Months and Current Nine Months.  For the Prior Three Months, our refinery operations business segment recognized a gain of $2,299,678 on settled transactions and a loss of $1,528,840 on the change in value of open contracts from June 30, 2016 to September 30, 2016. For the Prior Nine Months, our refinery operations business segment recognized a loss of $1,445,244 on settled transactions and a loss of $1,143,490 on the change in value of open contracts from December 31, 2015 to September 30, 2016.

Liquidity and Capital Resources

Overview.

Historically, we relied on the profit share distribution and operations payments under a Joint Marketing Agreement with GEL, as well as LEH, to fund our liquidity needs.  As disclosed elsewhere in this Quarterly Report, beginning in the second quarter of 2016, LE experienced an adverse change in its relationship with Genesis/GEL involving a contract-related dispute.  This shift in the relationship negatively affected our customer relationships, prevented us from taking advantage of business opportunities, disrupted refinery operations, diverted management’s focus away from running the business, and impacted our ability to obtain financing.  Combined with decreased commodity prices throughout 2016, our resultant financial state raised substantial doubt about our ability to continue as a going concern, which doubt has increased because of the Final Arbitration Award.  (As discussed elsewhere within this “Liquidity and Capital Resources” section, management has determined that there is substantial doubt about our ability to continue as a going concern due to consecutive quarterly net losses, inadequate working capital, the Final Arbitration Award, crude supply issues tied to access to capital, and defaults under secured loan agreements. See “Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern” for additional discussion related to going concern.)

As discussed elsewhere in this Quarterly Report, on August 11, 2017, the arbitrator delivered the Final Arbitration Award in the GEL Arbitration.  Among other matters, the Final Arbitration Award awarded damages, legal and administrative fees and court costs to GEL in the aggregate amount of approximately $31.3 million.  LE expects that it will be unable to pay the amounts awarded to GEL in full or in any substantial part.  A hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court of the Continuance Period to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into the GEL Letter Agreement, confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement.

GEL could have terminated the GEL Letter Agreement on the 45th day of the Continuance Period, or November 1, 2017, if GEL determined, in its sole discretion, that settlement discussions between the parties were not advancing to an acceptable resolution.  As previously disclosed, on November 1, 2017, LE and GEL amended the GEL Letter Agreement to extend the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017.  The Amended GEL Letter Agreement prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period.

Veritex delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements.  The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under these loan agreements, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.  The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential 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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

We can provide no assurance as to whether negotiations with GEL will result in a settlement or as to the potential terms of any such settlement or whether Veritex would approve any such settlement.  If LE is unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially adversely affected and we likely would be required to seek protection under bankruptcy laws.

Following the cessation of crude supplies under the Crude Supply Agreement with GEL, we put in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company.  This new supplier currently provides us with adequate amounts of crude oil and condensate, and having crude supply continuity has boosted our customers’ confidence in our performance ability and enabled us to slowly rebuild counter-party relationships.  However, we are currently evaluating the effects of the Final Arbitration Award on our business, financial condition and results of operations.  In addition to the matters described above, the Final Arbitration Award could materially and adversely affect our ability to procure adequate amounts of crude oil and condensate and our relationships with our customers.

Currently, we rely on revenue from operations, LEH and its affiliates (including Jonathan Carroll), and borrowings under bank facilities to meet our liquidity needs. During the Current Nine Months, we continued aggressive actions to improve operations and liquidity. We began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure. We also completed construction of several new petroleum storage tanks at the Nixon Facility.  Increasing petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 17,000 bpd, and (iii) provides an opportunity to generate additional tank rental revenue by leasing to third-parties.  Additional ongoing efforts to improve operations and liquidity include restructuring customer contracts on more favorable terms as they come up for renewal.  Management believes that it is taking the appropriate steps to improve our financial stability. However, there can be no assurance that our plan will be successful, LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all.  Among other factors, the Final Arbitration Award could prevent us from successfully executing our plan.

Crude Oil and Condensate Supply.

Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate on favorable terms.  We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company.  This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Management believes that it is taking the appropriate steps to improve our financial stability.  However, there can be no assurance that our plan will be successful, LEH and its affiliates (including Jonathan Carroll) will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all.  If our plan is unsuccessful, it could affect our ability to acquire adequate supplies of crude oil and condensate under the existing contract or otherwise.  Among other factors, the Final Arbitration Award could prevent us from successfully executing our plan and could have a material adverse effect on our ability to procure adequate amounts and crude oil and condensate from our current supplier or otherwise.  Further, because our existing crude supply contract is a month-to-month arrangement, there can be no assurance that crude oil and condensate supplies will continue to be available under this contract in the future.

Cash Flow.

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Cash flow from operations
Adjusted income (loss) from operations	$4,504,921	$(879,483)	$(21,600,038)	$(8,335,348)
Change in assets and current liabilities	(5,673,761)	(5,493,430)	15,464,667	3,657,961
Total cash inflows (outflows) from operations	(1,168,840)	(6,372,913)	(6,135,371)	(4,677,387)
Cash inflows (outflows)
Proceeds from issuance of debt	3,677,953	6,898,931	3,677,953	6,898,931
Payments on debt	(265,063)	(469,541)	(1,120,267)	(1,414,406)
Net activity on related-party debt	(2,288,717)	-	967,977	-
Capital expenditures	(369,518)	(4,182,747)	(1,777,219)	(11,255,725)
Total cash inflows (outflows)	754,655	2,246,643	1,748,444	(5,771,200)
Total change in cash flows	$(414,185)	$(4,126,270)	$(4,386,927)	$(10,448,587)

For the Current Three Months, we experienced negative cash flow from operations of $1,168,840 compared to negative cash flow from operations of $6,372,913 for the Prior Three Months. The $5,204,073 improvement in cash flow from operations between the periods was primarily the result of more favorable refining margins and payment of accounts payable at a slower rate in the Current Three Months compared to the Prior Three Months.

For the Current Nine Months, we experienced negative cash flow from operations of $6,135,371 compared to negative cash flow from operations of $4,677,387 for the Prior Nine Months. The $1,457,984 decline in cash flow from operations between the periods was primarily the result of an increase in accounts receivable.

Working Capital.

During the Current Three Months, net cash used in financing activities totaled $1,124,173 compared to net cash provided by financing activities totaling $6,429,390 in the Prior Three Months.  For the Current Nine Months, net cash provided by financing activities totaled $3,525,663 compared to net cash provided by financing activities totaling $5,484,525.  Working capital provided by financing activities represented advances from LEH and its affiliates (including Jonathan Carroll) under promissory notes.  (See “Part I, Item 1. Financial Statements – Note (8) Related Party Transactions and Note (10) Long-Term Debt, Net,” as well as “Contractual Obligations – Related Party” within the Liquidity and Capital Resources section for additional disclosures with respect to related party promissory notes.)

We had a working capital deficit of $67,084,694 at September 30, 2017 compared to a working capital deficit of $37,812,263 at December 31, 2016. Excluding long-term debt, we had a working capital deficit of $27,328,649 at September 30, 2017, compared to working capital of $5,599,927 at December 31, 2016. The significant increase in working capital deficit between the periods primarily related to the Final Arbitration Award and a decrease in cash and cash equivalents.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

As discussed elsewhere within this “Liquidity and Capital Resources” section, the contract-related dispute with GEL and the Final Arbitration Award has affected our ability to obtain working capital through financing.  Although LE is currently in settlement discussions with GEL, we expect this to continue for the foreseeable future.  We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements.  There can be no assurance that LEH and its affiliates (including Jonathan Carroll) will continue to fund our working capital requirements.

Capital Spending.

Capital improvements primarily relate to construction of new petroleum storage tanks to add to existing petroleum storage capacity. Due to the Final Arbitration Award, capital spending in the Current Three Months was minimal.  During the Current Nine Months, we completed several new tanks for which construction began during 2016. Increasing petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 17,000 bpd, and (iii) provides an opportunity to generate additional tank rental revenue by leasing to third-parties.  When the Nixon Facility expansion project is complete, total crude oil, condensate, and refined petroleum products storage capacity at the plant will exceed 1,000,000 bbls.

Capital expenditures at the Nixon Facility are being funded by Veritex through long-term debt that we secured in 2015.  Available funds under these loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets.  Restricted cash (current portion) represents funds to pay outstanding construction invoices and to fund construction contingencies.  Restricted cash (current portion) totaled $1,500,380 and $3,347,835 at September 30, 2017 and December 31, 2016, respectively.  Restricted cash, non-current represents funds held in our disbursement account with Veritex to complete construction of new petroleum storage tanks. Restricted cash, noncurrent totaled $150,530 and $1,582,305 at September 30, 2017 and December 31, 2016, respectively.

Total capital expenditures for the periods indicated were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Capital expenditures financed by:
Cash disbursements	$369,518	$4,182,747	$1,777,219	$11,255,725
Accounts payable(1)	169,283	8,330	1,650,910	2,601,709
	$538,801	$4,191,077	$3,428,129	$13,857,434

(1)   Represents construction-related vendor invoices awaiting payment from the loan disbursement account.

See “Part I, Item 1. Financial Statements – Note (10) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

Contractual Obligations.

Related Party.  See “Part I, Item 1. Financial Statements – Note (8) Related Party Transactions” in this Quarterly Report for a summary of the agreements we have in place with related parties.

GEL.  See “Part I, Item 1A. Risk Factors” in our Annual Report, as well as “Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern – Final GEL Arbitration Award" in this Quarterly Report for disclosures related to the contract-related dispute with GEL and the Final Arbitration Award.

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

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Indebtedness.

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

	June 30,	December 31,
	2017	2016
First Term Loan Due 2034 (in default)	$23,382,570	$23,924,607
Second Term Loan Due 2034 (in default)	9,553,728	9,729,853
LEH Loan Agreement	4,000,000	4,000,000
Notre Dame Debt	4,977,953	1,300,000
March Ingleside Note	1,168,748	722,278
March Carroll Note	282,907	592,412
Capital Leases	8,427	135,879
Term Loan Due 2017	-	184,994
	43,374,333	40,590,023
Less:  Current portion of long-term debt, net	(39,756,045)	(32,212,336)
Less:  Unamoritized debt issue costs	(2,166,633)	(2,262,997)
	$1,451,655	$6,114,690

Principal payments on long-term debt totaled $265,063 in the Current Three Months compared to $469,541 in the Prior Three Months.  Payments on long-term debt totaled $1,120,267 in the Current Nine Months compared to $1,414,406 in the Prior Nine Months.

As described elsewhere in this Quarterly Report, Veritex notified obligors that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034 and Second Term Loan Due 2034.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the secured loan agreements.  LE also failed to replenish a payment reserve account as required.  The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under the secured loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under the loan agreements, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements.  Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.

See “Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern and Operating Risks, as well as Note (10) Long-Term Debt, Net” for additional disclosures related to long-term debt financial covenant violations and events of default.

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

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies

Long-Lived Assets.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets for the years ended December 31, 2016 and 2015.

Pipelines and Facilities Assets. Our pipelines and facilities are recorded at cost less any adjustments for depreciation or impairment.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with 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 were permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines.

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

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

Revenue Recognition.

Refined Petroleum Products Revenue.  Revenue from the sale of refined petroleum products is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred.  Transportation, shipping and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Rental Revenue.  We lease petroleum storage tanks to third-parties.  Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement.  Tank rental revenue is recognized on a straight-line basis as earned.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Asset Retirement Obligations.

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

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

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

Income Taxes.

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that some portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any NOL carryforwards. At September 30, 2017 and December 31, 2016, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of September 30, 2017 and December 31, 2016.

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

(See “Part I, Item 1. Financial Statements - Note (15) Income Taxes” for further information related to income taxes.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Recently Adopted Accounting Guidance

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

ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (A Consensus of the FASB Emerging Issues Task Force. In November 2016, FASB issued ASU 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. We adopted this accounting pronouncement effective December 31, 2016. Accordingly, our consolidated statement of cash flows for the nine months ended September 30, 2016 was changed to combine restricted cash with cash and cash equivalents.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11, which requires an entity to measure inventory at the lower of cost or net realizable value.  We adopted this accounting pronouncement effective January 1, 2017.  The adoption of ASU 2015-11 did not have a significant impact on our consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision of, and with the participation of our management, including our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report. Based on our evaluation, our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

Management concluded that our internal control over financial reporting was effective as of December 31, 2016. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three and nine months ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

PART II OTHER INFORMATION

 ITEM 1.  LEGAL PROCEEDINGS

GEL Contract-Related Dispute and Final Arbitration Award

See "Part I, Item 1. Financial Statements – Note (1) Organization – Going Concern – Final Arbitration Award " of this Quarterly Report for disclosures related to the GEL contract-related dispute and Final Arbitration Award. In addition, see Part II, Item 1. Legal Proceedings” in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017 as filed with the SEC for additional information regarding the contract related dispute and Final Arbitration Award.

Other Legal Matters

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

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2017 and June 30, 2017, as well as 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.  Except for the below risk factors, there have been no material changes in our assessment of our risk factors from those set forth in our Annual Report.

The adverse outcome in the arbitration of the contract-related dispute with GEL could have a material adverse effect on our business, financial condition and results of operations and materially adversely affect the value of an investment in our common stock.

As 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 the Joint Marketing Agreement.  On August 11, 2017, the arbitrator delivered the Final Arbitration Award.  The Final Arbitration Award denied all LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims.  Among other matters, the Final Arbitration Award awarded damages, legal and administrative fees and court costs to GEL in the aggregate amount of approximately $31.3 million.

A hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for the Continuance Period to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into the GEL Letter Agreement, effective September 18, 2017, confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement. Under the GEL Letter Agreement, GEL could have terminated the Letter Agreement on the 45th day of the Continuance Period, or November 1, 2017, if it determined, in its sole discretion, that settlement discussions between the parties were not advancing to an acceptable resolution. On November 1, 2017, LE and GEL entered into the Amended GEL Letter Agreement to extend the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017. The Amended GEL Letter Agreement prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

Veritex notified obligors that the Final Arbitration Award constitutes an event of default under secured loan agreements with Veritex.  The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. 

We can provide no assurance as to whether negotiations with GEL will result in a settlement, as to potential terms of any such settlement, whether Veritex would approve of any such settlement, or whether Veritex will exercise its rights and remedies under secured loan agreements. If: (i) we are unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement, (ii) GEL seeks to confirm and enforce the Final Arbitration Award, or (iii) Veritex exercises its rights and remedies under the secured loan agreements, our business, financial condition and results of operations will be materially adversely affected and we likely would be required to seek protection under bankruptcy laws. In addition, our ability to procure adequate amounts of crude oil and condensate and our relationships with our customers could materially and adversely be affected, and the trading prices of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety.

For additional information regarding the Final Arbitration Award, the GEL Letter Agreement, and their potential effects on our business, financial condition and results of operations, see the notes to our financial statements in “Part I, Item 1. Financial Statements,” “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 1. Legal Proceedings” in this Quarterly Report.

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

As described elsewhere in this Quarterly Report, Veritex notified obligors that the Final Arbitration Award constitutes an event of default under secured loan agreements with Veritex.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE and LRM were in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the secured loan agreements.  LE also failed to replenish a payment reserve account as required.  The occurrence of events of default under the secured loan agreements permits Veritex to declare the amounts owed under the secured loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors' obligations under the loan agreements, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements.  Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.

59

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

There can be no assurance that: (i) our assets or cash flow would be sufficient to fully repay borrowings under outstanding long-term debt, either upon maturity or if accelerated, (ii) LE and LRM would be able to refinance or restructure the payments on the long-term debt, and/or (iii) Veritex will provide future waivers. Defaults under secured loan agreements and any exercise by Veritex of its rights and remedies related to such defaults may have a material adverse effect on the trading prices of our common stock and on the value of an investment in our common stock, and holders of our common stock could lose their investment in our common stock in its entirety, particularly if we are required to seek bankruptcy protection because of the exercise by Veritex of such rights and remedies.

For additional information regarding defaults under our secured loan agreements and their potential effects on our business, financial condition and results of operations, see the notes to our financial statements in “Part I, Item 1. Financial Statements” and “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Quarterly 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 (10) Long-Term Debt, Net” for disclosures related to defaults on our debt.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered into on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Sixth Amendment to Notre Dame Debt. Pursuant to a Sixth Amendment to the Notre Dame Debt, entered into on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended by the Additional Principal. The Additional Principal was used to make payments to GEL in the amount of $3,648,742 in connection with the GEL Letter Agreement to reduce the balance of the Final Arbitration Award.

60

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

ITEM 6.  EXHIBITS

Exhibits Index

No.	Description
10.1	Letter Agreement between GEL Tex Marketing, LLC, Lazarus Energy, LLC, Blue Dolphin Energy Company, Lazarus Energy Holdings, LLC, and Jonathan Carroll effective September 18, 2017.
10.2	Amendment to Letter Agreement between GEL Tex Marketing, LLC, Lazarus Energy, LLC, Blue Dolphin Energy Company, Lazarus Energy Holdings, LLC, and Jonathan Carroll dated November 1, 2017.
10.3	Debt Assumption Agreement by and among Lazarus Energy Holdings, LLC, Lazarus Energy, LLC, and John H. Kissick dated effective September 18, 2017.
10.4	Sixth Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of September 18, 2017.
31.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.LAB	XBRL Label Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

*           All exhibits listed are filed herewith.

61

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/17

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BLUE DOLPHIN ENERGY COMPANY (Registrant)
Date: November 16, 2017	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)

Date:  November 16, 2017	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

62

EX-10.1

 Exhibit 10.1

September 18, 2017

Jonathan Carroll

Lazarus Energy, LLC

Blue Dolphin Energy Company

Lazarus Energy Holdings, LLC

By Electronic Mail (JCarroll@lazarusenergy.com)

Re:        

GEL Tex Marketing, LLC v. Lazarus Energy, LLC

Stipulation Regarding Confirmation and Enforcement of Final Award

Dear Jonathan:

In order to facilitate further discussions, GEL Tex Marketing, LLC (“GEL Tex”) and Lazarus Energy, LLC (“Lazarus”) have come to an agreement regarding the confirmation and enforcement of the Final Award issued on August 11, 2017 in AAA Arbitration Case No. 02-16-0001-5548. This letter memorializes that agreement (“Letter Agreement”). Blue Dolphin Energy Company (“BDEC”) and Lazarus Energy Holdings, LLC (“LEH”), both affiliates of Lazarus and Jonathan Carroll, are also party to this Letter Agreement. Lazarus, BDEC, LEH, and Jonathan Carroll are collectively referred to herein as the “Lazarus Parties”.

GEL Tex and the Lazarus Parties stipulate and agree to the following.

●Before September 18, 2017 at 9:30 am, GEL Tex and Lazarus will jointly notify the 165th District Court of Harris County (the “District Court”) that, in order to facilitate settlement discussions between the parties, the hearing to confirm the Final Award in Cause No. 2016-28397 will be continued for no more than 90 days (the “Continuance Period”). Notwithstanding the foregoing, on November 1, 2017 (the 45thday of the Continuance Period), in the event GEL Tex determines in its sole discretion that the settlement discussions between the parties are not advancing to an acceptable resolution, then GEL Tex shall have the option to immediately terminate this Letter Agreement by delivering written notice to Lazarus’ counsel listed below.

●Before September 18, 2017 at 9:30 am, the Lazarus Parties will notify the District Court that it has no objection to the immediate disbursement of all funds in the Court’s Registry to GEL Tex, which will be applied to reduce the balance of the Final Award.

●Prior to the hearing on September 18, 2017, the Lazarus Parties will wire $1.5 million to GEL Tex, which will be applied to reduce the balance of the Final Award.

●During the Continuance Period, the Lazarus Parties and GEL Tex agree to work together in good faith to negotiate and document the terms of a settlement and payment structure to resolve all of their disputes and obligations, including those relating to and arising from the Final Award.

●During the Continuance Period, the Lazarus Parties agree to permit and, if requested by GEL Tex, to facilitate, direct contact between GEL Tex and the Lazarus Parties’ banks and other lenders.

1

Mr. Jonathan Carroll

September 18, 2017

Page Two

●During the Continuance Period, the Lazarus Parties agree to cooperate with Opportune to review the business of each Lazarus Party and their affiliates as well as Jonathan and Gina Carroll.

●The Lazarus Parties hereby waive all objections to confirmation of the Final Award. Notwithstanding this waiver, GEL Tex agrees that GEL Tex will take no action to confirm, enforce, collect, execute upon, perfect, or exercise any remedies in connection with the Lazarus Parties’ waiver and/or the Final Award prior to the earlier to occur of (1) the expiration of the Continuance Period without the parties agreeing to a settlement and payment structure to resolve all of the disputes between them, including those relating to and arising from the Final Award, and (2) the termination of this Letter Agreement. The Lazarus Parties’ waiver set forth in this paragraph shall survive the expiration and/or termination of this Letter Agreement.

●Without the prior written consent of GEL Tex, which consent may be granted or withheld in GEL Tex's sole discretion, the Lazarus Parties and all of their respective affiliates shall: (i) not incur or become liable for any debt (other than under such existing debt instruments and amounts as reflected in Attachment A hereto, which includes the borrowing necessary to fund the $1.5 million payment referenced above); (ii) not permit to exist any liens or other encumbrances on any of its assets (other than the specific existing liens and other encumbrances list in Attachment A hereto); (iii) not transfer, assign, sell, lease, or convey any asset to any person or entity other than (a) refined product sales for fair value in the ordinary course of business by Lazarus to unaffiliated third parties (except jet sales to LEH for fair value for further sale to the Defense Logistics Agency), (b) payment to its third-party trade creditors in the ordinary course of business, and (c) scheduled debt payments to third-party lenders under the existing debt instruments and payment terms reflected in Attachment A hereto; (iv) not engage in any affiliate transactions or other arrangements of any kind whatsoever (other than the existing affiliate transactions specifically described in Attachment A hereto) and not amend or modify any terms of such existing affiliate transactions; (v) permit GEL Tex at any time to inspect its property, examine its books and records, and discuss its affairs with its officers, accountants, attorneys, Veritex, and the USDA; (vi) fail to pay debts generally as they become due or become party to (or made the subject of) any bankruptcy, reorganization, liquidation, or similar proceeding; (vii) not form or make an investment in any new subsidiary or business venture or merge or consolidate with any other entity, or acquire material assets of any other entity, or allow any changes in the current equity ownership of any Lazarus Party or any of their affiliates; (viii) not amend or supplement any of their debt instruments, liens, or organizational documents, or change their names or the location of their principal place of business; and (ix) not take any action to challenge the validity or enforceability of this Letter Agreement or to violate the terms herein in any manner. Notwithstanding subsection (i) of this paragraph, it is understood that as to debt of Jonathan and Gina Carroll in their individual capacities to which the other Lazarus Parties have no liability or obligation, Attachment A hereto contains only such debt and amounts that represent material indebtedness of such individuals.

2

Mr. Jonathan Carroll

September 18, 2017

Page Three

●GEL Tex has the right to immediately terminate this Letter Agreement upon any violation of this Letter Agreement by any Lazarus Party by providing written notice to Lazarus’ counsel listed below of GEL Tex’s termination of this stipulation Letter Agreement.

●GEL Tex and the Lazarus Parties agree that this Letter Agreement may be executed in separate parts delivered by electronic means that, taken together, will be deemed to be one instrument. GEL Tex and each Lazarus Party represent and warrant that this Letter Agreement has been approved and authorized by all necessary action and the execution hereof does not violate any agreement to which it is a party.

[Signature Page Follows.]

3

Mr. Jonathan Carroll

September 18, 2017

Page Four

If these terms accurately state the stipulation and agreement between GEL Tex and the Lazarus Parties, please sign where indicated below and we will file this Letter Agreement with the 165th Judicial District Court.

Very truly yours,

DLA Piper LLP (US)		DLA Piper LLP (US)
/s/ THOMAS R. CALIFANO		/s/ CHRISTINA P. MACCIO
Thomas R. Califano		Christina P. Maccio
Partner		Partner
Attorney for GEL Tex Marketing, LLC		Attorney for GEL Tex Marketing, LLC
Agreed:
/s/ JONATHAN CARROLL
Jonathan Carroll, in his individual capacity
Lazarus Energy, LLC
Blue Dolphin Energy Company
Lazarus Energy Holdings, LLC
/s/ JONATHAN CARROLL
By:	Jonathan Carroll
/s/ FRANK A MEROLA
Frank A. Merola
Attorney for Lazarus Energy, LLC
/s/ BRYAN MELTON
Bryan Melton
Attorney for Lazarus Energy, LLC

4

Attachment “A”

Material Agreements and Indebtedness

		Entity	Debt / Commercial Agreements	Term	Payment Structure	Liens / Security Interest	Related Party(ies)
Attachment “A”Material Agreements and IndebtednessI.		Blue Dolphin Energy Company (“BDCO”)	●Amended and Restated Promissory Note dated June 30, 2017 between LEH, as Lender, and BDCO, as Borrower (~$2.5 Million BDCO-LEH Note)	Matures January 2019.	Interest accrues at 8.0%; balloon payment due at maturity.	None	LEH
			●Amended and Restated Promissory Note dated March 31, 2017 between Ingleside, as Lender, and BDCO, as Borrower (~$1.1 Million BDCO-Ingleside Note)	Matures January 2019.	Interest accrues at 8.0%; balloon payment due at maturity.	None	Ingleside
			●Amended and Restated Promissory Note dated March 31, 2017 between Lazarus Capital, as Lender, and BDCO, as Borrower (~$0.1 Million BDCO-Carroll Note)	Matures January 2019.	Revolver; principal and interest paid quarterly; interest accrues at 8.0%; payment 50% cash and 50% BDCO common stock.	None	Lazarus Capital / Jonathan Carroll
			●Amended and Restated Operating Agreement dated April 1, 2017 between BDCO, LE, and LEH	Attachment “A”Material Agreements and IndebtednessExpires April 1, 2020, upon written notice of either party of a material breach, or upon 90 days’ notice by BDCO’s Board of Directors if the Board determines the agreement is no longer in BDCO’s best interests.	Attachment “A”Material Agreements and IndebtednessLEH is reimbursed at cost plus 5% for reasonable costs incurred while LEH performs the Services.	N/A	LE LEH
	A.	Lazarus Energy, LLC (“LE”)	●Loan Agreement dated June 22, 2015 among Sovereign Bank, NA (“Sovereign”), as Lender, LE, as Borrower, and Jonathan Pitts Carroll, Sr., BDCO, LRM, and LEH, as Guarantors ($25.0 Million Veritex USDA Loan)	Matures June 2034.	Principal and interest paid monthly; interest accrues at Prime + 2.75%; monthly payment currently $198,786.	Secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a $1.0 million payment reserve account held by the bank, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll.	BDCO LRM LEH Jonathan Carroll
			●Promissory Note dated June 1, 2006 between LE, as Maker, and Notre Dame Investors, as Payee ($8.0 Million Notre Dame / Kissick Loan)	Matures June 2018.	Balloon payment due at maturity.	Secured by Deed of Trust, Security Agreement and Financing Statements, which encumber the Nixon Facility and general assets of LE.	None

A-1

Attachment “A”

Material Agreements and Indebtedness

  

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

●Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LE and Jonathan Carroll (Guaranty Fee Agreement ties to $25.0 Million Veritex USDA Loan; amounts owed to Jonathan Carroll captured under ~$1.0 Million BDCO-Carroll Note)	Terminates when $25.0 Million Veritex USDA Loan paid in full.	2% fee per annum, paid monthly on outstanding balance.	N/A	Jonathan Carroll
●Amended and Restated Operating Agreement dated April 1, 2017 between BDCO, LE, and LEH	Expires April 1, 2020, upon written notice of either party of a material breach, or upon 90 days’ notice by BDCO’s Board of Directors if the Board determines the agreement is no longer in BDCO’s best interests.	LEH is reimbursed at cost plus 5% for reasonable costs incurred while LEH performs the Services.	N/A	BDCO LEH
●Product Sales Agreement between LE and LEH dated April 1, 2017 (jet fuel sales)	Earliest to occur of: (i) one-year term expiring March 31, 2018 plus a 30-day carryover or (ii) delivery of the maximum quantity of jet fuel.	$0.035 per gallon above relevant Platt’s Gulf Coast Pipeline Index on the sales date plus cost of additives at $0.01635 per gallon.	N/A	LEH
●Ground Lease Agreement dated June 1, 2015 between LE and LRM	Terminates March 2035.	Base rent at $10,000 per month.	N/A	LRM
●Tolling Agreement dated May 24, 2016 between LMT and LE (LE’s use of barge loading facility in Ingleside, Texas)	5-year term expiring May 2021.	Monthly reservation fee of $50,400 up to 84,000 gallons per day; additional $0.02 per gallon for tolling volumes greater than 210,000 per quarter.	N/A	LRM
●Tolling Agreement dated October 1, 2015 between LRM, as Owner, and LE, as Customer (LE’s use of certain Nixon Facility Processing Units)	12-year term expiring October 2027.	Quarterly reservation fee of $180,000 up to 210,000 gallons per quarter; additional $0.05 per gallon for tolling volumes greater than 210,000 per quarter.	N/A	LRM
●Amended and Restated Tank Lease Agreement dated January 1, 2016 between Ingleside and LE (periodic additional product storage needs)	Terminated April 2017.	N/A	N/A	Ingleside

A-2

Attachment “A”

Material Agreements and Indebtedness

  

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

B.	Lazarus Refining & Marketing, LLC (“LRM”)	●Loan Agreement dated December 4, 2015 among Sovereign, as Lender, LRM, as Borrower, and Jonathan Pitts Carroll, Sr., BDCO, LE, and LEH, as Guarantors ($10.0 Million Veritex USDA Loan)	Matures December 2034.	Principal and interest paid monthly; interest accrues at Prime + 2.75%; monthly payment currently $74,111.	Secured by: (i) a second priority lien on the rights of LE in the Nixon Facility 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 Sovereign has a second priority lien in such leases subordinate to a prior lien granted by LRM to Sovereign to secure obligations of LRM under the $2.0 Million Sovereign Loan; and (v) all other collateral as described in the security documents	BDCO LE LEH Jonathan Carroll
		●Loan and Security Agreement dated May 2, 2014 among Sovereign and LRM ($2.0 Million Sovereign Loan)	Retired.	NA	Secured by assignment of certain leases of LRM and certain assets of LEH; guaranteed by Jonathan Carroll.	Jonathan Carroll
		●Master Lease Agreement / Amended and Restated Schedule No. 001 dated January 7, 2015 between LRM and Tetra Financial Group, Inc.	Matures November 2017.	Quarterly payment of $44,258.	Secured by cash collateral.	N/A
		●Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LRM and Jonathan Carroll (Guaranty Fee Agreement ties to $10.0 Million Veritex USDA Loan; amounts owed to Jonathan Carroll captured under ~$1.0 Million BDCO-Carroll Note)	Terminates when $10.0 Million Veritex USDA Loan paid in full.	2% fee per annum, paid monthly on outstanding balance.	N/A	Jonathan Carroll
		●Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LRM and Jonathan Carroll (Guaranty Fee Agreement ties to $2.0 Million Sovereign Loan; amounts owed to Jonathan Carroll captured under ~$1.0 Million BDCO-Carroll Note)	Terminates when $2.0 Million Sovereign Loan paid in full.	2% fee per annum, paid monthly on outstanding balance.	N/A	Jonathan Carroll
		●Ground Lease Agreement dated June 1, 2015 between LE and LRM	Terminates March 2035.	Base rent at $10,000 per month.	N/A	LE
		●Tolling Agreement dated October 1, 2015 between LRM, as Owner, and LE, as Customer (LE’s use of certain Nixon Facility Processing Units)	12-year term expiring October 2027.	Quarterly reservation fee of $180,000 up to 210,000 gallons per quarter; additional $0.05 per gallon for tolling volumes greater than 210,000 per quarter.	N/A	LE

C.	Blue Dolphin Pipe Line Company (“BDPL”)	●Loan and Security Agreement dated August 15, 2016 between LEH, as Lender, and BDPL, as Debtor ($4.0 Million BDPL-LEH Loan)	Matures August 2018.	$500,000 payment per year; balloon payment due at maturity; interest accrues at 16.0%.	Secured by: (i) remaining payments due under Master Easement Agreement between BDPL and FLNG Land II, Inc. and (ii) real property (193 acres of BDPL-owned land) and fixtures and personal property located in Freeport, Texas.	LEH
D.	Blue Dolphin Services Company	None	N/A	N/A	N/A	N/A
E.	Blue Dolphin Exploration Company	None	N/A	N/A	N/A	N/A
F.	Blue Dolphin Petroleum Company	None	N/A	N/A	N/A	N/A
G.	Petroport, Inc.	None	N/A	N/A	N/A	N/A

A-3

Attachment “A”

Material Agreements and Indebtedness

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

I.	Lazarus Energy Holdings, LLC	●Note Purchase Agreement dated December 6, 2006 between LEH, Lazarus Refining & Marketing, LLC (previous LEH subsidiary), and Louisiana I, Louisiana II, LE and LTRII, as Issuers, and John Kissick and AP Energy Partners LLC, as Investors	SEE $2.0 MILLION KISSICK BRIDGE 1 AND $1.0 MILLION AP BRIDGE PROMISSORY NOTES BELOW	N/A	N/A	N/A
		●Promissory Note (8% Senior Note Due 2007) dated December 6, 2006 between Louisiana I, Louisiana II, LE and LTRII, as Issuers, and John Kissick, as Holder ($2.0 Million Kissick Bridge 1)	Matured; past due.	Balloon payment due at maturity; accrues interest at 8.0%; currently payments on demand.	Secured by Collateral Documents as defined in the Note Guaranty, the Gatehouse Guaranty, and the Gatehouse Mortgage.	LEH
		●Promissory Note (8% Senior Note Due 2007) dated December 6, 2006 between Louisiana I, Louisiana II, LE and LTRII, as Issuers, and AP Energy Partners LLC, as Holder ($1.0 Million AP Bridge 1)	Matured; past due.	Balloon payment due at maturity; accrues interest at 8.0%; currently payments on demand.	Secured by Collateral Documents as defined in the Note Guaranty, the Gatehouse Guaranty, and the Gatehouse Mortgage.	LEH
		●Note Purchase Agreement dated February 21, 2007 between LEH, Lazarus Refining & Marketing, LLC (previous LEH subsidiary), LE, Louisiana I, Louisiana II, LTRII, as Issuers, and Initial Noteholders, and Gatehouse Guarantor (~$2.9 Million Kissick Bridge 2)	Retired	N/A	N/A	N/A
		●Promissory Note (8% Senior Note) to John H. Kissick, as Holder ($1.0 Million Kissick Bridge 3)	Matured; past due.	Balloon payment due at maturity; accrues interest at 8.0%; currently payments on demand.	No security identified.	LEH
		●Loan and Security Agreement dated August 15, 2016 between John H. Kissick, as Lender, and LEH, as Debtor ($4.0 Million Kissick 2016 Note)	Matures October 2018.	$500,000 payment per year; balloon payment due at maturity; interest accrues at 16.0%.	Secured by substantially all of LEH’s personal property, as well as (i) the Property described in that certain Deed of Trust, Mortgage, Security Agreement, Assignment of Leases And Rents, Financing Statement And Fixture Filing dated as of August 15, 2016, executed by Debtor for the benefit of Lender; (ii) that certain Easement Agreement dated as of December 11, 2013, executed by BDPL and FLNG Land II, Inc.; and (iii) all Payment Rights described in that certain Collateral Assignment dated as of August 15, 2016, executed by Debtor in favor of Lender.	John H. Kissick
		●Promissory Note with Notre Dame Investors, Inc., as Holder ($1.5 Million Notre Dame/NDI Note)	Matures July 2025.	Accrues interest at 6.0%; current monthly payment of $13,068.	Secured by promissory note between NALIC and LEH.	LTRII
		●Promissory Note dated May 21, 2013 between LEH, as Maker, and Scoggin LLC, as Payee ($6.0 Million Scoggins Note)	Matures December 2020.	Semi-annual payments of $500,000.	Guaranteed by Louisiana I, Louisiana II, and LTRII.	Louisiana I Louisiana II LTRII

A-4

Attachment “A”

Material Agreements and Indebtedness

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

		●Promissory Note between North American Life Insurance Company, as Issuer, and LEH, as Holder ($2.0 Million NALIC Note)	Matures April 2024.	Accrues interest at 8.0%; current monthly payment of $20,000 to David Roberson.	No security identified.	Jonathan Carroll Gina Carroll
		●Loan and Security Agreement dated August 15, 2016 between LEH, as Lender, and BDPL, as Debtor ($4.0 Million BDPL-LEH Loan)	Matures August 2018.	$500,000 payment per year; balloon payment due at maturity; interest accrues at 16.0%.	Secured by: (i) remaining payments due under Master Easement Agreement between BDPL and FLNG Land II, Inc. and (ii) real property (193 acres of BDPL-owned land) and fixtures and personal property located in Freeport, Texas.	BDCO / BDPL
		●Amended and Restated Promissory Note dated June 30, 2017 between LEH, as Lender, and BDCO, as Borrower (~$2.5 Million BDCO-LEH Note)	Matures January 2019.	Interest accrues at 8.0%; balloon payment due at maturity.	N/A	BDCO
		●Amended and Restated Operating Agreement dated April 1, 2017 between BDCO, LE, and LEH	Expires April 1, 2020, upon written notice of either party of a material breach, or upon 90 days’ notice by BDCO’s Board of Directors if the Board determines the agreement is no longer in BDCO’s best interests.	LEH is reimbursed at cost plus 5% for reasonable costs incurred while LEH performs the Services.	N/A	BDCO LE
		●Terminal Services Agreement dated April 1, 2016 between LEH and LRM (storage of jet fuel)	Terminated April 2017.	N/A	N/A	LRM
A.	Lazarus Texas Refinery I, LLC (“LTRI”)	●Promissory Note to National Oil Recovery Corporation, as Holder (~$2.7 Million NORCO Note)	Retired.	N/A	N/A	N/A
B.	Lazarus Texas Refinery II, LLC (“LTRII”)	None	N/A	N/A	N/A	N/A
C.	Lazarus Louisiana Refinery, LLC (“Louisiana I”)	None	N/A	N/A	N/A	N/A
D.	Lazarus Louisiana Refinery II, LLC (“Louisiana II”)	None	N/A	N/A	N/A	N/A
E.	Lazarus Forest Products, LLC (“LFP”)	●Loan Modification Agreement dated December 12, 2011 between One World Bank, NA (“One World”), as Lender, LO, and LFP, as Borrowers, and Jonathan P. Carroll, Sr. and LEH, as Guarantors (SEE BELOW LFP USDA AND SBA LOANS)	No change to terms.	Principal and interest paid monthly; balloon payment due at maturity.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LO Jonathan Carroll LEH

A-5

Attachment “A”

Material Agreements and Indebtedness

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

		●Loan Agreement dated December 21, 2009 between One World, as Lender, LO and LFP, as Borrowers ($1.6 Million LFP SBA Loan)	Matures December 2019.	Principal and interest paid monthly; balloon payment due at maturity; monthly payment currently $18,448.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LO LEH Jonathan Carroll
		●Promissory Note dated December 31, 2008 between One World, as Lender, and J&D Lumber, Inc., as Borrower / Assumption Agreement dated December 31, 2009 wherein LO and LFP assumed J&D Lumber’s Obligations as Borrowers ($3.3 Million LFP USDA Loan)	Matures December 2028.	Principal and interest paid monthly; balloon payment due at maturity; monthly payment currently $22,596.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LO LEH Jonathan Carroll
F.	Lazarus Oklahoma, LLC (“LO”)	●Loan Modification Agreement dated December 12, 2011 between One World, as Lender, LO, and LFP, as Borrowers, and Jonathan P. Carroll, Sr. and LEH, as Guarantors (SEE BELOW LO USDA AND SBA LOANS)	No change to term.	Principal and interest paid monthly; balloon payment due at maturity.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LFP Jonathan Carroll LEH
		●Loan Agreement dated December 21, 2009 between One World, as Lender, LO and LFP, as Borrowers ($1.6 Million LO SBA Loan)	Matures December 2019.	Principal and interest paid monthly; balloon payment due at maturity; monthly payment currently $18,448.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LFP LEH Jonathan Carroll
		●Promissory Note dated December 31, 2008 between One World, as Lender, and J&D Lumber, Inc., as Borrower / Assumption Agreement dated December 31, 2009 wherein LO and LFP assumed J&D Lumber’s Obligations as Borrowers ($3.3 Million LO USDA Loan)	Matures December 2028.	Principal and interest paid monthly; balloon payment due at maturity; monthly payment currently $22,596.	Secured by collateral comprised of real estate described in the Mortgages and the personal property described in the Security Agreements; guaranteed by LEH and Jonathan Carroll.	LFP LEH Jonathan Carroll
G.	Lazarus Energy Development, LLC	None	N/A	N/A	N/A	N/A
H.	Lazarus Environmental, LLC	None	N/A	N/A	N/A	N/A
I.	Lazarus Marine Terminal I, LLC (“LMT”)	●Loan and Security Agreement dated May 31, 2016 among Sovereign, as Lender, and LMT, as Borrower ($1.0 Million Veritex Loan)	Matures May 2019.	Principal and interest paid monthly; interest accrues at Prime + 2.75%; monthly payment currently $31,648.	Personal property of Borrower; guaranteed by Jonathan Carroll and LEH	Jonathan Carroll LEH
		●Tolling Agreement dated May 24, 2016 between LMT and LE (LE’s use of barge loading facility in Ingleside, Texas)	5-year term expiring May 2021.	Monthly reservation fee of $50,400 up to 84,000 gallons per day; additional $0.02 per gallon for tolling volumes greater than 210,000 per quarter.	N/A	LE
J.	Lazarus Midstream GP, LLC	None	N/A	N/A	N/A	N/A

A-6

Attachment “A”

Material Agreements and Indebtedness

 

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

K.	Lazarus Midstream Partners, LP	None	N/A	N/A	N/A	N/A
L.	Lazarus Midstream LLC	None	N/A	N/A	N/A	N/A
M.	Lazarus Midstream Acquisition Corp.	None	N/A	N/A	N/A	N/A

A-7

Attachment “A”

Material Agreements and Indebtedness

 

Entity Debt / Commercial Agreements Term Payment Structure Liens / Security Interest Related Party(ies)

III.		Jonathan P. Carroll
	A.	Ingleside Crude, LLC (“Ingleside”)	●Loan Agreement dated July 18, 2013 between Green Bank, NA (“Green Bank”), as Lender, and Ingleside, as Borrower ($1.9 Million funded out of $3.2 Million)(Green Bank SBA Loan I)	Matures July 2023.	Monthly payment of principal and interest; interest accrues at Prime + 2.75%; monthly payment currently $28,131.	Secured by 1st perfected security interest, subject to no other liens, in personal property (equipment and machinery); pledge of corporate stock (100,000 shares of BDCO common stock), an SBA guarantee, and a perfected 1st lien and assignment of leases on all existing, renovated and new tanks located at the Ingleside, Texas tank farm; additional collateral includes assignment of life insurance policy on Jonathan Carroll; loan guaranteed by Jonathan Carroll.	Jonathan Carroll
			●Construction Loan Agreement dated October 7, 2015 between Green Bank, N.A., as Lender, and Ingleside, as Borrower ($1.6 Million Green Bank SBA Loan II)	Matures October 2025.	Principal and interest; interest accrues at Prime + 2.75%; monthly payment currently $18,460.	Secured by all of Borrower’s property, now owned or hereafter acquired and wherever located, together with all replacements, accessions, proceeds, and products, to wit: all business assets, including without limitation, all Equipment, Fixtures, Inventory, Investment Property, Documents, Instruments, Chattel Paper, Accounts, Contract Rights, Deposit Accounts, General Intangibles, Intellectual Property and Farm Products, including without limitation those items of property described in the Security Agreement exhibits, incorporated therein for all purposes.; guaranteed by Jonathan Carroll.	Jonathan Carroll
			●Amended and Restated Promissory Note dated March 31, 2017 between Ingleside, as Lender, and BDCO, as Borrower (~$1.1 Million BDCO-Ingleside Note)	Matures January 2019.	Interest accrues at 8.0%; balloon payment due at maturity.	None	BDCO
			●Amended and Restated Tank Lease Agreement dated January 1, 2016 between Ingleside and LE (periodic additional product storage needs)	Terminated April 2017.	N/A	N/A	LE
	B.	Lazarus Capital, LLC (f/k/a Lazarus Financial, LLC) (“Lazarus Capital”)	●Amended and Restated Promissory Note dated March 31, 2017 between Lazarus Capital, as Lender, and BDCO, as Borrower (~$0.1 Million BDCO-Carroll Note)	Matures January 2019.	Revolver; principal and interest paid quarterly; interest accrues at 8.0%; payment 50% in cash and 50% in BDCO common stock.	None	BDCO
	C.	Carroll & Company Financial Holdings, LP	None	N/A	N/A	N/A	N/A

A-8

Lazarus Energy Holdings LLC and Related Entities

Notes Payable Summary

As of September 15, 2017

Rough Draft - Includes Estimates

Debt Description	Principal	Outstanding Interest	Total	Maturity	Payment Structure
LEH Debt
Kissick Bridge 1	2,291,555	1,535,514	3,827,069	Past-due	Balloon payment at maturity
AP Bridge 1	1,145,778	767,757	1,913,535	Past-due	Balloon payment at maturity
Kissick Bridge 2	-	-	-			*Retired
Kissick Bridge 3	1,000,000	576,512	1,576,512	Past-due	Balloon payment at maturity
Kissick 2016 Note	4,000,000	700,000	4,700,000	10/31/18	Balloon payment at maturity
Notre Dame Note	1,107,483	132,898	1,240,381	7/1/25	Monthly payments of $13,068
Scoggins Note	3,220,511	362,307	3,582,819	12/15/20	Semi-annual payments of $500,000
North America Life Ins. Co.	1,252,319	-	1,252,319	4/15/24	Monthly payments of $20,000	*Interest through 2010
LEH Total	$14,017,647	$4,074,988	$18,092,635
LEH Subs Debt
LFP One World Bank Loan (SBA)	1,112,874	94,594	1,207,469	12/21/19	Monthly payments of $18,448 with balloon at maturity
LO One World Bank Loan (USDA)	2,862,458	223,033	3,085,491	12/31/28	Monthly payments of $22,596 with balloon at maturity
LTR I Norco Note	-	-	-			*Retired
LMTI Veritex Loan	611,111	42,608	653,719	5/31/19	Monthly payments of $31,648 (variable)
LEH Subs Total	$4,586,444	$360,236	$4,946,680
Blue Dolphin Debt
Related-Party LEH Note	500,000	-	500,000	1/1/19	Balloon payment at maturity
(LE Portion of LEH Note)	-	-	-
(LRM Portion of LEH Note)	277,747	-	277,747
(Other Portions of LEH Note)	222,253	-	222,253
Related-Party IngCru Note	1,123,404	-	1,123,404	1/1/19	Balloon payment at maturity
(LE Portion of IngCru Note)	1,095,149	-	1,095,149
(LRM Portion of IngCru Note)	3,000	-	3,000
(Other Portions of IngCru Note)	25,254	-	25,254
Related-Party Carroll Note	204,846	-	204,846	N/A	Revolver, fully paid quarterly 50% in stock and 50% in cash
(LE Portion of Carroll Note)	156,846	-	156,846
(LRM Portion of Carroll Note)	48,000	-	48,000
(Other Portions of Carroll Note)	-	-	-
Blue Dolphin Total	$1,828,250	$-	$1,828,250
Blue Dolphin Subs Debt
LE Veritex Term Loan (USDA)	23,440,052	30,000	23,470,052	6/22/34	Monthly payments of $198,786 (variable)
LE Notre Dame Loan (Kissick) (Deed)	4,964,141	1,829,867	6,794,008	1/2/18	Balloon payment at maturity
LRM Veritex Term Loan (USDA)	9,553,728	40,000	9,593,728	12/4/34	Monthly payments of $74,111
LRM Tetra Boiler Loan (Lease)	44,258	-	44,258	11/5/17	Quarterly payments of $44,258
LRM Sovereign Term Loan	-	-	-			*Retired
BDPL Related-Party LEH Loan (Freeport Deed)	4,000,000	700,000	4,700,000	8/15/18	One payment of $500,000 due, balloon payment at maturity
Blue Dolphin Subs Total	$42,002,180	$2,599,867	$44,602,047
Ingleside Crude Debt
Green Bank Loan I (SBA)	1,645,465	-	1,645,465	7/18/23	Monthly payments of $28,131 (variable)
Green Bank Loan II (SBA)	1,400,107	-	1,400,107	10/6/25	Monthly payments of $18,460 (variable)
Ingleside Crude Total	$3,045,572	$-	$3,045,572

EX-10.2

 Exhibit 10.2

Amendment to Letter Agreement

November 1, 2017

Jonathan Carroll

Lazarus Energy, LLC

Blue Dolphin Energy Company

Lazarus Energy Holdings, LLC

By Electronic Mail (JCarroll@lazarusenergy.com)

Re:  

GEL Tex Marketing, LLC v. Lazarus Energy, LLC 

First Amendment to the Stipulation Regarding Confirmation and

Enforcement of Final Award Dated September 18, 2017

Dear Jonathan,

This is an amendment (the "Amendment") to the Stipulation Regarding Confirmation and Enforcement of Final Award Dated September 18, 2017 (the "Letter Agreement"). All capitalized terms used but not otherwise defined in this Amendment shall have the meanings given to such terms in the Letter Agreement.

The Letter Agreement gave GEL Tex the right to terminate the Letter Agreement on November 1, 2017 if settlement discussions between the Lazarus Parties and GEL Tex were not advancing to an acceptable resolution. In order to facilitate ongoing discussions, GEL Tex and the Lazarus Parties have agreed to change the date on which GEL Tex has the right to terminate the Letter Agreement with certain conditions. Accordingly, GEL Tex and the Lazarus Parties amend the Letter Agreement and agree to the following.

●

GEL Tex's right to terminate the Letter Agreement shall be changed from November 1, 2017 to November 28, 2017.

●

In addition to permitting: (i) GEL Tex at any time to inspect the books and records of the Lazarus Parties and all of their respective affiliates and (ii) cooperating with Opportune LLP to review the business of each Lazarus Party and their affiliates as well as Jonathan and Gina Carroll, the Lazarus Parties agree that between November 1, 2017 and November 28, 2017, from time to time, upon Opportune LLP's request, the Lazarus Parties and their affiliates shall grant Opportune LLP access to examine the books and records of the Lazarus Parties and all of their respective affiliates.

●

On or before November 1, 2017, the Lazarus Parties shall pay an advance in the amount of $50,000.00 to Opportune LLP for the estimated fees and expenses incurred for its examinations of the books and records between November 1, 2017 and November 28, 2017. If the fees and expenses actually incurred during this period exceed the amount of the $50,000.00 advance, the Lazarus Parties shall pay any excess fees and expenses presented to the Lazarus Parties by invoice within two (2) business days of presentation

of the invoice; provided, however, that such excess fees and expenses shall not exceed $10,000.00

●

Opportune LLP agrees to provide the Lazarus Parties periodic invoices for the actual cost incurred for its examinations of the books and records between November 1, 2017 and November 28, 2017. Opportune LLP shall remit to the Lazarus Parties any amounts advanced to Opportune LLP which exceed the costs and fees for the actual work performed.

●

If the Lazarus Parties fail to timely pay either the $50,000.00 advance payment or an Opportune LLP invoice described above (up to an aggregate maximum of $60,000.00), GEL Tex has the right to immediately terminate the Letter Agreement and this Amendment by providing written notice to Lazarus' counsel listed below of GEL Tex's termination.

●

The Lazarus Parties shall not make any prepayments on any debts listed in Attachment A. Except as described below, the Lazarus Parties and GEL Tex agree that the only debts the Lazarus Parties can pay between November 1, 2017 and the end of the Continuance Period are the debts payable in the ordinary course of business as described in the Letter Agreement.

●

Between November 1, 2017 and the end of the Continuance Period, the Lazarus Parties agree to temporarily suspend the payments on the following debts/commercial agreements:

o

The Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LE and Jonathan Carroll (Guaranty Fee Agreement ties to $25.0 Million Veritex USDA Loan; amounts owed to Jonathan Carroll captured under ~$1.0 million BDCO-Carroll Note); as described on page A-2 of Attachment A;

o

The Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LRM and Jonathan Carroll (Guaranty Fee Agreement ties to $10.0 Million Veritex USDA Loan; amounts owed to Jonathan Carroll captured under ~$1.0 million BDCO-Carroll Note) as described on page A-3 of Attachment A; and

o

The Amended and Restated Guaranty Fee Agreement dated April 1, 2017 between LRM and Jonathan Carroll (Guaranty Fee Agreement ties to $2.0 Million Sovereign Loan; amounts owed to Jonathan Carroll captured under ~$1.0 million BDCO-Carroll Note) as described on page A-3 of Attachment A.

●

GEL Tex and the Lazarus Parties agree that the Amendment may be executed in separate parts delivered by electronic means that, taken together, will be deemed to be one instrument. GEL Tex and each Lazarus Party represent and warrant that the Amendment has been approved and authorized by all necessary action and the execution hereof does not violate any agreement to which it is a party.

-2-

●

Except as set forth in the Amendment, the Letter Agreement is unaffected and shall continue in full force and effect in accordance with its terms. If there is a conflict between the Amendment and the Letter Agreement, the terms of the Amendment will prevail.

[Signature Pages Follow]

-3-

If these terms accurately state the amendments to the Letter Agreement between GEL Tex and the Lazarus Parties, please sign where indicated below and we will file this Amendment with the 165th Judicial District Court.

Very truly yours,

Haynes & Boone LLP		DLA Piper LLP (US)
/s/ CHARLES A. BECKHAM, JR.		/s/ CHRISTINA P. MACCIO
Charles A. Beckham, Jr.		Christina P. Maccio
Partner		Partner
Attorney for GEL Tex Marketing, LLC		Attorney for GEL Tex Marketing, LLC
Agreed:
/s/ JONATHAN CARROLL
Jonathan Carroll, in his individual capacity
Lazarus Energy, LLC
Blue Dolphin Energy Company
Lazarus Energy Holdings, LLC
/s/ JONATHAN CARROLL
By:	Jonathan Carroll
Stroock & Stroock & Lavan LLP		Susman Godfrey LLP
/s/ FRANK A MEROLA		/s/ BRYAN MELTON
Frank A. Merola		Bryan Melton
Attorney for Lazarus Energy, LLC		Attorney for Lazarus Energy, LLC

-4-

EX-10.3

 Exhibit 10.3

DEBT ASSUMPTION AGREEMENT

This DEBT ASSUMPTION AGREEMENT (this “Agreement”), dated effective as of September 18, 2017 (the “Effective Date”), is by and among Lazarus Energy Holdings, LLC, a Delaware limited liability company (“LEH”), Lazarus Energy, LLC, a Delaware limited liability company (“LE”), and John H. Kissick, whose address is c/o Ares Management, LLC, 2000 Avenue of the Stars, 12th Floor, Los Angeles, California 90067 (“Kissick”).

WHEREAS, LEH is the obligor on certain notes (as such notes have been amended, modified or supplemented to the Effective Date, the “LEH Notes”) issued pursuant to that certain Note Purchase Agreement, dated as of February 21, 2007, by and among LEH, the other Issuers (as defined therein), the Initial Noteholders (as defined therein) and the Gatehouse Guarantor (as defined therein) (as such Note Purchase Agreement has been amended, modified or supplemented to the Effective Date, the “LEH Note Purchase Agreement”);

WHEREAS, as of the Effective Date, (i) the sum of the aggregate principal amount of and accrued and unpaid interest on the LEH Notes is $3,677,953 (the “LEH Note Balance”) and (ii) Kissick is the holder of all of the LEH Notes;

WHEREAS, LE is the Maker of that certain Promissory Note, dated as of June 1, 2006, under which Notre Dame Investors, Inc. was the original Payee (as such Promissory Note has been amended, modified or supplemented to the Effective Date, the “LE Note”);

WHEREAS, as of the Effective Date, Kissick is the Payee of the LE Note;

WHEREAS, on the Effective Date, LEH paid, on LE’s behalf, certain obligations of LE totaling $3,648,742 (the “LEH Payment”) under that certain Letter Agreement dated as of the Effective Date among GEL Tex Marketing, LLC, LE, Blue Dolphin Energy Company, LEH and Jonathan Carroll;

WHEREAS, LE and LEH intend that, as of the Effective Date and in consideration of LEH’s making of the LEH Payment on LE’s behalf, LE will assume LEH’s obligations in respect of the LEH Note Balance by means of (i) the cancelation of the LEH Notes and (ii) the increase of the principal amount of the LE Note by the amount of the LEH Note Balance, each on the terms set forth herein (the “Debt Assumption”);

WHEREAS, Kissick is willing to agree to Debt Assumption;

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

1.Acknowledgement of LEH Payment. LE hereby acknowledges that LEH made the LEH Payment on LE’s behalf. LEH hereby agrees that the Debt Assumption constitutes full satisfaction of any and all obligations of LE to LEH in respect of the LEH Payment.

1

2.Amendment of the LE Note. To effect the Debt Assumption, contemporaneously with the execution and delivery of this Agreement by the parties hereto, LE and Kissick shall enter into the Sixth Amendment to Promissory Note in the form attached hereto as Exhibit A effective as of the Effective Date (the “LE Note Amendment”).

3.Cancellation of LEH Notes.

(a)Kissick and LEH agree that, effective as of the Effective Date and immediately upon the execution and delivery by LE and Kissick of the LE Note Amendment, and without further action by Kissick or LEH, (i) the LEH Notes and the indebtedness represented thereby shall be canceled, (ii) all amounts owed by LEH under the LEH Notes and the LEH Note Purchase Agreement shall be deemed paid and discharged in full, and (iii) neither LEH nor Kissick shall have any further obligations, liabilities, duties or rights under the LEH Notes and the LEH Note Purchase Agreement.

(b)Without limitation of the foregoing, Kissick hereby releases and forever discharges LEH and its affiliates from any and all obligations arising under the LEH Notes and the LEH Note Purchase Agreement and from any and all manner of actions, suits, claims and demands whatsoever that Kissick has or may have against LEH or its affiliates, arising out of or in any way connected to the LEH Notes and the LEH Note Purchase Agreement, in each case whether arising before, on or after the Effective Date. For the avoidance of doubt, the foregoing release shall not extend to any rights of Kissick under the LE Note and the LE Note Amendment. Further, and without limitation of the foregoing, Kissick agrees that, from and after the Effective Date, Kissick shall have no recourse to LEH for payment of the LEH Note Balance.

(c)Without limitation of the foregoing, LEH hereby releases and forever discharges Kissick and his affiliates from any and all obligations arising under the LEH Notes and the LEH Note Purchase Agreement and from any and all manner of actions, suits, claims and demands whatsoever that LEH has or may have against Kissick or his affiliates, arising out of or in any way connected to the LEH Notes and the LEH Notes Agreement, in each case whether arising before, on or after the Effective Date. For the avoidance of doubt, the foregoing release shall not extend to any rights of LE under the LE Note and the LE Note Amendment.

4.Representations and Warranties.

(a)Representations and Warranties of LEH. LEH hereby represents and warrants to LE and Kissick that:

(i)LEH has been duly organized and is validly existing and in good standing under the laws of the State of Delaware.

(ii)LEH is duly qualified as a foreign entity and in good standing in each jurisdiction where such qualification is required, except to the extent the failure to be so qualified or in good standing would not have a material adverse effect on the ability of LEH to execute, deliver and perform its obligations under this Agreement.

(iii)LEH has the limited liability company power and authority to execute, deliver and perform its obligations under this Agreement.

2

(iv)The execution and delivery of this Agreement by LEH and the performance by LEH of its obligations hereunder have been duly authorized by all necessary limited liability company action on the part of LEH.

(v)This Agreement has been duly executed and delivered by LEH.

(vi)Assuming the due authorization, execution and delivery of this Agreement by the other parties hereto, this Agreement constitutes the legal, valid and binding obligation of LEH, enforceable against LEH in accordance with its terms.

(vii)The execution and delivery of this Agreement by LEH and the performance by LEH of its obligations hereunder do not (i) conflict with or violate any provision of the certificate of formation or limited liability company agreement of LEH, (ii) conflict with, violate or result in a breach or default (with or without due notice or lapse of time or both) under any contract or other instrument to which LEH is a party or by which LEH or any of its properties is bound, (iii) violate any judgment, order, ruling or decree applicable to LEH as a party in interest, (iv) violate any laws or regulations applicable to LEH or (v) require that LEH obtain any consent or authorization of, or make any filing with, any person, entity or governmental authority.

(b)Representations and Warranties of LE. LE hereby represents and warrants to LEH and Kissick that:

(i)LE has been duly organized and is validly existing and in good standing under the laws of the State of Delaware.

(ii)LE is duly qualified as a foreign entity and in good standing in each jurisdiction where such qualification is required, except to the extent the failure to be so qualified or in good standing would not have a material adverse effect on the ability of LE to execute, deliver and perform its obligations under this Agreement and the LE Note Amendment.

(iii)LE has the limited liability company power and authority to execute, deliver and perform its obligations under this Agreement and the LE Note Amendment.

(iv)The execution and delivery of this Agreement and the LE Note Amendment by LE and the performance by LE of its obligations hereunder and thereunder have been duly authorized by all necessary limited liability company action on the part of LE.

(v)This Agreement and the LE Note Amendment have been duly executed and delivered by LE.

(vi)Assuming the due authorization, execution and delivery of this Agreement and the LE Note Amendment by the other parties hereto and thereto, this Agreement and the LE Note Amendment constitute the legal, valid and binding obligations of LE, enforceable against LE in accordance with their terms.

3

(vii)The execution and delivery of this Agreement and the LE Note Amendment by LE and the performance by LE of its obligations hereunder and thereunder do not (i) conflict with or violate any provision of the certificate of formation or limited liability company agreement of LE, (ii) conflict with, violate or result in a breach or default (with or without due notice or lapse of time or both) under any contract or other instrument to which LE is a party or by which LE or any of its properties is bound, (iii) violate any judgment, order, ruling or decree applicable to LE as a party in interest, (iv) violate any laws or regulations applicable to LE or (v) require that LE obtain any consent or authorization of, or make any filing with, any person, entity or governmental authority.

5.Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without giving effect to any conflict or choice of law provision that would result in the imposition of the laws of another state.

6.Further Assurances. The parties hereto agree to execute, acknowledge and deliver, as appropriate and commercially reasonable, any and all such other and additional instruments, notices and other documents and to perform such other acts as may be reasonably necessary to give full effect to the transactions contemplated by this Agreement and the LE Note Amendment.

7.Counterparts and Headings. This Agreement may be executed in any number of counterparts, all of which shall constitute one and the same agreement, and any party hereto may execute this Agreement by signing and delivering one or more counterparts. Delivery of an executed counterpart of this Agreement electronically or by facsimile shall be effective as delivery of an original executed counterpart of this Agreement. The headings in this Agreement are for reference only and do not affect the interpretation of this Agreement.

8.Severability. If any term or provision of this Agreement is invalid, illegal or unenforceable in any jurisdiction, such invalidity, illegality or unenforceability shall not affect any other term or provision of this Agreement or invalidate or render unenforceable such term or provision in any other jurisdiction.

9.Amendment and Waivers. No amendment to or rescission, termination or discharge of this Agreement shall be effective unless it is in writing and signed by each party to this Agreement. No waiver of any provision of this Agreement shall be effective unless it is in writing and signed by the party granting such waiver.

10.Successors and Assigns; Third Party Beneficiaries. This Agreement or any rights or obligations hereunder, may not be assigned by any party hereto without the prior written consent of each of the other parties hereto. All provisions of this Agreement by or for the benefit of any party hereto shall bind and inure to the benefit of such party’s successors and permitted assigns. No provision of this Agreement is intended to confer any rights, benefits, remedies, obligations or liabilities hereunder upon any person or entity other than the parties hereto and their respective successors and permitted assigns, except that the provisions of Sections 3(b) and 3(c) relating to releases of affiliates of parties hereto shall be to the benefit of such affiliates.

4

11.Entire Agreement. This Agreement, together with the other agreements and instruments referred to herein, constitutes the entire agreement and understanding of the parties hereto with respect to the matters that are the subject of this Agreement and supersedes all prior agreements and understandings, whether written or oral, with respect to such matters.

[Remainder of page intentionally left blank. Signature pages to follow.]

5

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered by the undersigned parties effective as of the Effective Date.

LAZARUS ENERGY HOLDINGS, LLC
By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	Managing Member

LAZARUS ENERGY, LLC
By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President
/s/ JOHN H. KISSICK
JOHN H. KISSICK

Signature Page to Debt Assumption Agreement

EXHIBIT A

SIXTH AMENDMENT TO PROMISSORY NOTE

EX-10.4

 Exhibit 10.4

SIXTH AMENDMENT TO PROMISSORY NOTE

This SIXTH AMENDMENT TO PROMISSORY NOTE (the “Amendment”) by and between Lazarus Energy, LLC, a Delaware limited liability company (“Maker”), and John H. Kissick (“Payee”) is made effective as of September 18, 2017 (the “Effective Date”). The Maker and the Payee shall be referenced individually as a “Party” and collectively as “Parties”.

WHEREAS, the Maker and the Payee are Parties to that certain Promissory Note dated June 1, 2006 (as amended, restated, supplemented or otherwise modified from time to time in accordance with its provisions, the “Note”), to which reference is hereby made for all purposes; and

WHEREAS, pursuant to the terms of that certain Debt Assumption Agreement dated as of the Effective Date among Lazarus Energy Holdings, LLC, the Maker and the Payee, the Parties desire to amend the Note as set forth herein.

NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1.           

Definitions. Capitalized terms used and not defined in this Amendment shall have the respective meanings given them in the Note.

2.          

Amendments to the Note. The Note is hereby amended as follows:

(a)             

The Principal Amount of the Note is hereby increased, effective as of the Effective Date, by $3,677,953 (such amount, the “Additional Principal Amount”).

(b)             

Notwithstanding anything in the Note to the contrary, interest on the Additional Principal Amount shall begin to accrue on the Effective Date.

3.          

Accrued and Unpaid Interest. The Payee and the Maker hereby acknowledge and agree that (a) the outstanding Principal Amount of the Note as of the Effective Date, including the Additional Principal Amount, is $4,964,141, and (b) the accrued and unpaid interest on the Note as of the Effective Date is $1,829,867.

4.          

Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Note and the Deed of Trust are and shall remain in full force and effect and are hereby ratified and confirmed by the Maker. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of the Note or Deed of Trust or for any purpose except as expressly set forth herein or a consent to any further or future action on the part of the Maker that would require the waiver or consent of the Payee.

5.          

Successors and Assigns. This Amendment shall inure to the benefit of and be binding upon the Payee and the Maker and each of their respective successors and assigns.

1

Counterparts. This Amendment may be executed in any number of counterparts, all of which shall constitute one and the same agreement, and any Party hereto may execute this Amendment by signing and delivering one or more counterparts. Delivery of an executed counterpart of this Amendment electronically or by facsimile shall he effective as delivery of an original executed counterpart of this Amendment.

[Remainder of page intentionally left blank; signature page to follow]

2

IN WITNESS WHEREOF, theParties hereto have executed this Amendment effective as of the Effective Date.

Lazarus Energy, LLC, as Maker
By:	/s/ JONATHAN P. CARROLL
	Name: Jonathan P. Carroll
	Title: President

John H. Kissick, as Payee
By:	/s/ JOHN H. KISSICK
	Name: John H. Kissick

Signature Page to Sixth Amendment to Promissory Note

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: November 16, 2017	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: November 16, 2017	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 16, 2017	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: November 16, 2017	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 16, 2017
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, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,818,371
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2017

XML

Consolidated Balance Sheets (Unaudited) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 44,931	$ 1,152,628
Restricted cash	1,500,380	3,347,835
Accounts receivable, net	627,604	2,022,166
Accounts receivable, related party	1,060,154	1,161,589
Prepaid expenses and other current assets	1,631,352	1,046,191
Deposits	138,957	138,957
Inventory	2,775,440	2,075,538
Total current assets	7,778,818	10,944,904
Total property and equipment, net	64,396,811	62,324,463
Restricted cash, noncurrent	150,530	1,582,305
Surety bonds	230,000	205,000
Trade name	303,346	303,346
Total long-term assets	65,080,687	64,415,114
TOTAL ASSETS	72,859,505	75,360,018
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion	35,756,045	31,712,336
Long-term debt, related party, current portion	4,000,000	500,000
Accounts payable	2,759,479	14,552,383
Accounts payable, related party	823,200	369,600
Asset retirement obligations, current portion	17,065	17,510
Accrued expenses and other current liabilities	1,220,074	1,281,582
Accrued arbitration award payable	27,627,863	0
Interest payable, current portion	2,659,786	323,756
Total current liabilities	74,863,512	48,757,167
Long-term liabilities:
Asset retirement obligations, net of current portion	2,225,661	2,010,129
Deferred revenues and expenses	52,119	83,390
Long-term debt less unamortized debt issue costs, net of current portion	0	1,300,000
Long-term debt, related party, net of current portion	1,451,655	4,814,690
Long-term interest payable, net of current portion	0	1,691,383
Total long-term liabilities	3,729,435	9,899,592
TOTAL LIABILITIES	78,592,947	58,656,759
Commitments and contingencies (Note 18)
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock (0.01 par value, 20,000,000 shares authorized; 10,818,371 and 10,624,714 shares issued at September 30,2017 and December 31, 2016, respectively	108,184	106,248
Additional paid-in capital	36,877,604	36,818,528
Accumulated deficit	(42,719,230)	(19,421,517)
Treasury stock (0 and 150,000 shares at cost at September 30, 2017 and December 31, 2016, respectively	0	(800,000)
Total stockholders' equity (deficit)	(5,733,442)	16,703,259
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$ 72,859,505	$ 75,360,018

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,818,371	10,624,714
Common stock, shares Outstanding	10,818,371	10,624,714
Treasury stock, shares	0	150,000

XML

Consolidated Statements of Operations (Unaudited) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 66,132,959	$ 53,951,293	$ 174,667,617	$ 126,546,716
Tank rental revenue	766,133	717,487	2,173,555	1,624,461
Other operations	0	19,526	0	71,865
Total revenue from operations	66,899,092	54,688,306	176,841,172	128,243,042
COST OF OPERATIONS
Cost of refined products sold	58,785,827	51,689,474	165,185,276	125,316,249
Refinery operating expenses	1,758,005	3,153,646	6,222,771	9,468,409
Joint Marketing Agreement profit share	0	965,627	0	392,062
Other operating expenses	67,969	100,974	183,095	298,566
Arbitration award and associated fees	0	0	24,338,628	0
General and administrative expenses	1,239,813	891,210	2,854,294	1,503,533
Depletion, depreciation and amortization	455,437	504,719	1,355,780	1,415,519
Bad debt recovery	0	0	0	(139,868)
Accretion expense	71,844	28,186	215,532	84,558
Total cost of operations	62,378,895	57,333,836	200,355,376	138,339,028
Income (loss) from operations	4,520,197	(2,645,530)	(23,514,204)	(10,095,986)
OTHER INCOME (EXPENSE)
Easement, interest and other income	26,657	157,840	409,739	415,700
Interest and other expense	(601,335)	(485,659)	(2,027,748)	(1,305,125)
Gain on disposal of property	0	0	1,834,500	0
Total other income (expense)	(574,678)	(327,819)	216,491	(889,425)
Income (loss) before income taxes	3,945,519	(2,973,349)	(23,297,713)	(10,985,411)
Income tax benefit	0	1,034,798	0	3,735,040
Net income (loss)	$ 3,945,519	$ (1,938,551)	$ (23,297,713)	$ (7,250,371)
Loss per common share:
Basic	$ 0.36	$ (0.19)	$ (2.19)	$ (0.69)
Diluted	$ 0.36	$ (0.19)	$ (2.19)	$ (0.69)
Weighted average number of common shares outstanding:
Basic	10,818,371	10,464,715	10,644,654	10,460,849
Diluted	10,818,371	10,464,715	10,644,654	10,460,849

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
OPERATING ACTIVITIES
Net loss	$ 3,945,519	$ (1,938,551)	$ (23,297,713)	$ (7,250,371)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization			1,355,780	1,415,519
Unrealized gain on derivatives			0	1,143,490
Deferred tax benefit			0	(3,735,040)
Amortization of debt issue costs			96,363	96,364
Accretion of asset retirement obligations	71,844	28,186	215,532	84,558	$ 112,744
Common stock issued for services			30,000	50,000
Recovery of bad debt	0	0	0	(139,868)
Changes in operating assets and liabilities
Accounts receivable			1,394,563	(1,815,584)
Accounts receivable, related party			101,435	0
Prepaid expenses and other current assets			(585,161)	945,539
Deposits and other assets			(25,000)	570,444
Inventory			(699,902)	(1,011,662)
Accrued arbitration award			27,627,863	0
Accounts payable, accrued expenses and other liabilities			(12,802,731)	5,269,224
Accounts payable, related party			453,600	(300,000)
Net cash used in operating activities			(6,135,371)	(4,677,387)
INVESTING ACTIVITIES
Capital expenditures			(1,777,219)	(11,255,725)
Net cash used in investing activities			(1,777,219)	(11,255,725)
FINANCING ACTIVITIES
Proceeds from issuance of debt			3,677,953	6,898,931
Payments on debt			(1,120,267)	(1,414,406)
Net activity on related-party debt			967,977	0
Net cash provided by financing activities			3,525,663	5,484,525
Net decrease in cash, cash equivalents, and restricted cash			(4,386,927)	(10,448,587)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD			6,082,768	20,645,652	20,645,652
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	$ 1,695,841	$ 10,197,065	1,695,841	10,197,065	$ 6,082,768
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable			1,650,910	2,601,709
Financing of guaranty fees via long-term debt, related party			170,636	0
Conversion of related-party notes to common stock			831,012	0
Interest paid			1,573,996	1,827,794
Income taxes paid			$ 0	$ 0

XML

1. Organization

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Nature of Operations.  Blue Dolphin Energy Company (“Blue Dolphin,”) is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000-bpd crude oil and condensate processing facility located in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own pipeline assets and have leasehold interests in oil and gas properties. (See “Note (4) Business Segment Information” for further discussion of our business segments.)

Structure and Management. Blue Dolphin was formed as a Delaware corporation in 1986.  We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”). LEH operates and manages all our properties pursuant to an Amended and Restated Operating Agreement (the “Amended and Restated Operating Agreement”).  Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. Together LEH and Jonathan Carroll own approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). (See “Note (8) Related Party Transactions,” “Note (10) Long-Term Debt, Net” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Amended and Restated Operating Agreement, and Jonathan Carroll.)

Our operations are conducted through the following active subsidiaries:

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

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

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

● Blue Dolphin Petroleum Company, a Delaware corporation.

● Blue Dolphin Services Co., a Texas corporation.

See "Part I, Item 1. Business and Item 2. Properties” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding our operating subsidiaries, principal facilities, and assets.

References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires.

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

· Final GEL Arbitration Award – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all of the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages, legal and administrative fees and court costs to GEL in the aggregate amount of approximately $31.3 million.

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

Under the GEL Letter Agreement, GEL could have terminated the GEL Letter Agreement on the 45^th day of the Continuance Period, or November 1, 2017, if it determined, in its sole discretion, that settlement discussions between the parties were not advancing to an acceptable resolution. As previously disclosed, on November 1, 2017, LE and GEL amended the GEL Letter Agreement (the “Amended GEL Letter Agreement”) to extend the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017. The Amended GEL Letter Agreement prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period. If the parties are unable to reach an acceptable settlement with Genesis and GEL and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially affected, and we likely would be required to seek protection under bankruptcy laws.

·Veritex Secured Loan Agreement Event of Default – Veritex Community Bank (“Veritex”), as successor in interest to Sovereign Bank by merger, has delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex has informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements in light of the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future.

We are currently evaluating the effects of the Final Arbitration Award on our business, financial condition and results of operations. In addition to the matters described above, the Final Arbitration Award could materially and adversely affect our ability to procure adequate amounts of crude oil and condensate or our relationships with our customers. The contract-related dispute has negatively affected our customer relationships, prevented us from taking advantage of business opportunities, disrupted refinery operations, diverted management’s focus away from running the business, and impacted our ability to obtain financing.

We can provide no assurance as to whether negotiations with GEL will result in a settlement or as to the potential terms of any such settlement or whether Veritex would approve any such settlement. If LE is unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition and results of operations will be materially adversely affected and we likely would be required to seek protection under bankruptcy laws.

Operating Risks.  Successful execution of our business plan depends on several key factors, including having adequate crude oil and condensate supplies, increasing sales of refined petroleum products, and meeting contractual obligations. For the three and nine months ended September 30, 2017, execution of our business plan was negatively impacted by several factors, including:

● Net Losses – We saw an improvement in net income for the three months ended September 30, 2017.  For the three months ended September 30, 2017, we reported net income of $3,945,519, or income of $0.36 per share, compared to a net loss of $1,938,551, or a loss of $0.19 per share, for the three months ended September 30, 2016.  The $0.55 per share increase between the periods was primarily the result of favorable refining margins in the current three-month period. For the nine months ended September 30, 2017, we reported a net loss of $23,297,713, or a loss of $2.19 per share, compared to a net loss of $7,250,371, or a loss of $0.69 per share, for the nine months ended September 30, 2016.  The $1.50 per share increase in net loss between the periods was primarily the result of the Final Arbitration Award.

● Working Capital Deficits – We had a working capital deficit of $67,084,694 at September 30, 2017 compared to a working capital deficit of $37,812,263 at December 31, 2016. Excluding long-term debt, we had a working capital deficit of $27,328,649 at September 30, 2017, compared to working capital of $5,599,927 at December 31, 2016. The significant increase in working capital deficit between the periods primarily related to the Final Arbitration Award and a decrease in cash and cash equivalents.

● Termination of Relationship with Genesis and GEL – As previously disclosed and discussed elsewhere in this Quarterly Report, LE ceased purchases of crude oil and condensate from GEL under the Crude Supply Agreement in November 2016 and suspended the marketing and sale of refined petroleum products under the Joint Marketing Agreement following the processing of all crude oil and condensate supplied by GEL.

● Crude Supply Issues – We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by the contract-related dispute with GEL and other factors, as noted above.  The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts of crude oil and condensate from our current supplier or otherwise.

● Financial Covenant Defaults – In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE and LRM were in violation of certain financial covenants in obligors’ secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2017 due to existing or potential events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to any proposed settlement with GEL or provide future waivers of any financial covenant defaults, which may have an adverse impact on our financial position and results of operations.

During the nine months ended September 30, 2017, we continued aggressive actions to improve operations and liquidity.  We began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure.  We also completed construction of several new petroleum storage tanks at the Nixon Facility. Increasing petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 17,000 bpd, and (iii) provides an opportunity to generate additional tank rental revenue by leasing to third-parties.  Additional ongoing efforts to improve operations and liquidity include restructuring customer contracts on more favorable terms as they come up for renewal.  Management believes that it is taking the appropriate steps to improve our financial stability.  However, there can be no assurance that our plan will be successful, LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all.  Among other factors, the Final Arbitration Award could prevent us from successfully executing our plan.

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

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

-   Note (8) Related Party Transactions

-   Note (10) Long-Term Debt, Net

-   Note (18) Commitments and Contingencies –Legal Matters

-   Note (19) Subsequent Events

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

-   GEL Contract-Related Dispute and Final Arbitration Award

-   Results of Operations

-   Liquidity and Capital Resources

● Part II, Item 1. Legal Proceedings

● Part II, Item 1A. Risk Factors

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2. Basis of Presentation

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. 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, 2016 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, 2017 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2017, or for any other period.

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3. Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

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.  Cash and cash equivalents were $44,931 at September 30, 2017 compared to cash and cash equivalents of $1,152,628 at December 31, 2016.

Restricted Cash. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies.  Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks. At September 30, 2017, total restricted cash was $1,650,910, comprised of restricted cash (current portion) totaling $1,500,380 and restricted cash, noncurrent totaling $150,530.  At December 31, 2016, total restricted cash was $4,930,140, comprised of restricted cash (current portion) totaling $3,347,835 and restricted cash, noncurrent totaling $1,582,305 (See “Note (10) Long-Term Debt, Net” for additional disclosures related to our loan agreements with Veritex.)

Accounts Receivable and Allowance for Doubtful Accounts. Our accounts receivable consists of customer obligations due in the ordinary course of business.  Since we have a small number of customers with individually large amounts due on any given date, we evaluate potential and existing customers’ financial condition, credit worthiness, and payment history to minimize credit risk. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods. If necessary, we establish an allowance for doubtful accounts to estimate the amount of probable credit losses.  Allowance for doubtful accounts totaled $0 both at September 30, 2017 and December 31, 2016.

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 refined products sold.  (See “Note (6) Inventory” for additional disclosures related to our inventory.)

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets for any period 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”) 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.  However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines.

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

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

(See “Note (7) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name.  At September 30, 2017 and December 31, 2016, trade name totaled $303,346. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2016. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2016.

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability.  (See “Note (10) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

Revenue Recognition.

Refined Petroleum Products Revenue. Revenue from the sale of refined petroleum products is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Rental Revenue. We lease petroleum storage tanks to both related parties and third-parties.  Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement.  Tank rental revenue is recognized on a straight-line basis as earned.

Easement Revenue. Revenue from land easement fees was associated with a Master Easement Agreement between BDPL and FLNG Land II, Inc., a Delaware corporation (“FLNG”).  Easement revenue was recognized monthly as earned and was included in other income.  In February 2017, BDPL sold approximately 15 acres of property located in Brazoria County Texas to FLIQ Common Facilities, LLC, an affiliate of FLNG.  In conjunction with the sale of real estate, the Master Easement Agreement was terminated.

Pipeline Transportation Revenue. Revenue from our pipeline operations was derived from fee-based contracts and was typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue was recognized when volumes were physically delivered for the customer through the pipeline.  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.  (See “Note (4) Business Segment Information” for further discussion related to pipeline transportation revenue.)

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 the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.  A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2016. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2016.

FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.  (See “Note (15) 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.

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 it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

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

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations.  Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.  (See “Note (11) 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 (16) Earnings Per Share” for additional information related to EPS.)

Treasury Stock. We accounted for treasury stock under the cost method.  In May 2017, our treasury stock was re-issued.  The net change in share price after acquisition of the treasury stock was recognized as a component of additional paid-in-capital in our consolidated balance sheets.  (See “Note (12) Treasury Stock” for additional disclosures related to treasury stock.)

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

ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (A Consensus of the FASB Emerging Issues Task Force). In November 2016, FASB issued ASU 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. We adopted this accounting pronouncement effective December 31, 2016. Accordingly, our consolidated statement of cash flows for the nine months ended September 30, 2016 was changed to combine restricted cash with cash and cash equivalents.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11, which requires an entity to measure inventory at the lower of cost or net realizable value.  We adopted this accounting pronouncement effective January 1, 2017.  The adoption of ASU 2015-11 did not have a significant impact on our consolidated financial statements.

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 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.  In January 2017, FASB issued ASU 2017-04.  This guidance simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test.  For public business entities that are SEC filers, the amendments in ASU 2017-04 are effective for the annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019.  ASU 2017-04 should be applied prospectively, and early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.  We do not expect adoption of this guidance to have a significant impact on our consolidated balance sheets.

ASU 2016-02,Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2014-09, Revenue from Contracts with Customers.  In May 2014, FASB issued ASU 2014-09 and has since amended the standard with ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date; ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net); ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing; ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update); ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients; and ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.  These standards replace existing revenue recognition rules with a single comprehensive model to use in accounting for revenue arising from contracts with customers.  We are evaluating the impact that adoption of these ASU’s will have 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.

Reclassification.  Effective January 1, 2017, we reclassified amounts associated with our Pipeline Transportation operations to Corporate and Other.  (See “Note (4) Business Segment Information” for disclosures related to Corporate and Other.)

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4. Business Segment Information

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Business Segment Information

Effective January 1, 2017, we began reporting as a single business segment – Refinery Operations.  Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility.  Due to their small size, current and prior three and nine months’ amounts associated with Pipeline Transportation operations were reclassified to Corporate and Other. Pipeline Transportation operations diminished significantly as services to third-parties ceased and third-party wells along our pipeline corridor were permanently abandoned.  Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Three Months Ended September 30,
	2017									2016
	Segment									Segment
	Refinery			Corporate &						Refinery			Corporate &
	Operations			Other			Total			Operations			Other			Total
Revenue from operations	$	66,899,092		$	-		$	66,899,092		$	54,668,780		$	19,526		$	54,688,306
Less: cost of operations(1)		(61,456,546	)		(466,912	)		(61,923,458	)		(55,495,575	)		(367,915	)		(55,863,490	)
Other non-interest income(2)		-			-			-			-			156,396			156,396
Less: JMA Profit Share(3)		-			-			-			(965,627	)		-			(965,627	)
EBITDA(4)	$	5,442,546		$	(466,912	)				$	(1,792,422	)	$	(191,993	)
Depletion, depreciation and
amortization								(455,437	)								(504,719	)
Interest expense, net								(574,678	)								(484,215	)
Income (loss) before income taxes								3,945,519									(2,973,349	)
Income tax benefit								-									1,034,798
Net income (loss)							$	3,945,519								$	(1,938,551	)
Capital expenditures	$	538,801		$	-		$	538,801		$	4,191,077		$	-		$	4,191,077
Identifiable assets	$	70,791,236		$	2,068,269		$	72,859,505		$	85,585,499		$	10,816,664		$	96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Note (1) Organization - Going Concern - Final Arbitration Award” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

	Nine Months Ended September 30,
	2017									2016
	Segment									Segment
	Refinery			Corporate &						Refinery			Corporate &
	Operations			Other			Total			Operations			Other			Total
Revenue from operations	$	176,841,172		$	-		$	176,841,172		$	128,171,177		$	71,865		$	128,243,042
Less: cost of operations(1)		(197,706,434	)		(1,293,162	)		(198,999,596	)		(135,452,537	)		(1,078,910	)		(136,531,447	)
Other non-interest income(2)		-			-			-			(392,062	)		-			(392,062	)
Less: JMA Profit Share(3)		-			2,216,251			2,216,251			-			412,061			412,061
EBITDA(4)	$	(20,865,262	)	$	923,089					$	(7,673,422	)	$	(594,984	)
Depletion, depreciation and
amortization								(1,355,780	)								(1,415,519	)
Interest expense, net								(1,999,760	)								(1,301,486	)
Loss before income taxes								(23,297,713	)								(10,985,411	)
Income tax benefit								-									3,735,040
Net loss							$	(23,297,713	)							$	(7,250,371	)
Capital expenditures	$	3,428,129		$	-		$	3,428,129		$	13,857,434		$	-		$	13,857,434
Identifiable assets	$	70,791,236		$	2,068,269		$	72,859,505		$	85,585,499		$	10,816,664		$	96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses and the arbitration award and associated fees.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased.  (See “Note (18) Commitments and Contingencies – Legal Matters” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

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5. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 2017

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,
	2017		2016
Prepaid crude oil and condensate	$	1,332,439	$	-
Prepaid insurance		298,913		248,853
Short-term tax bond		-		505,000
Prepaid exise taxes		-		292,338
	$	1,631,352	$	1,046,191

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6. Inventory

9 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,		December 31,
	2017		2016
Crude oil and condensate	$	1,207,865	$	26,123
AGO		910,189		143,362
HOBM		341,660		212,987
Chemicals		156,535		182,751
Naphtha		135,554		533,580
Propane		18,377		11,318
LPG mix		5,260		1,293
Jet fuel		-		964,124
	$	2,775,440	$	2,075,538

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7. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2017

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,
	2017			2016
Refinery and facilities	$	51,432,434		$	50,814,309
Land		566,159			602,938
Other property and equipment		652,795			652,795
		52,651,388			52,070,042
Less:  Accumulated depletion, depreciation, and amortization		(8,041,024	)		(6,685,244	)
		44,610,364			45,384,798
Construction in progress		19,786,447			16,939,665
	$	64,396,811		$	62,324,463

We capitalize interest cost incurred on funds used to construct property, plant, and equipment.  The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life.  Interest cost capitalized was $3,413,428 and $2,108,298 at September 30, 2017 and December 31, 2016, respectively.

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8. Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions

We are party to several agreements with related parties.  We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions.

Related Parties.

LEH.  LEH is our controlling shareholder.  Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH.  Together LEH and Jonathan Carroll own approximately 81% of our Common Stock.  We are currently party to an Amended and Restated Operating Agreement, a Jet Fuel Sales Agreement, a Loan and Security Agreement, an Amended and Restated Promissory Note, and a Debt Assumption Agreement with LEH.

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

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

Jonathan Carroll.  Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin.  We are currently party to Amended and Restated Guaranty Fee Agreements and an Amended and Restated Promissory Note with Jonathan Carroll.

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.  Each quarter amounts we owe to related parties are settled with amounts owed to us by LEH and its affiliates under certain related-party agreements as discussed within this Note (8), Related Party Transactions.  As a result, these related-party transactions do not always reflect cash payments between the parties.

Operations Related Agreements.

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

Jet Fuel Sales Agreement.  We sell jet fuel and other products to LEH pursuant to a Jet Fuel Sales Agreement.  LEH resells these products to a government agency.   In support of the Jet Fuel Sales Agreement, we previously leased Nixon Facility petroleum storage tanks to LEH for the storage of the jet fuel under a Terminal Services Agreement (as described below).  The Jet Fuel Sales Agreement terminates on the earliest to occur of: (a) a one-year term expiring March 31, 2018 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 refined petroleum product sales in our consolidated statements of operations.

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

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

Tolling Agreement.  In May 2016, we entered a Tolling Agreement with LMT to facilitate loading and unloading of our petroleum products by barge at LMT’s dock facility in Ingleside, Texas.  The Tolling Agreement has a five-year term and may be terminated at any time by the agreement of both parties.  We pay LMT a flat monthly reservation fee of $50,400.  The monthly reservation fee includes tolling volumes up to 84,000 gallons per day.  Tolling volumes totaling more than 210,000 gallons per quarter are billed to us at $0.02 per gallon.  Amounts expensed as tolling fees to LMT under the Tolling Agreement are reflected in cost of refined products sold in our consolidated statements of operations.

Financial Agreements.

Loan and Security Agreement.  In August 2016, BDPL entered a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “LEH Loan Agreement”).  The LEH Loan Agreement matures in August 2018, and accrues interest at rate of 16.00%.  Under the LEH Loan Agreement, BDPL makes a payment to LEH of $500,000 per year.  A final balloon payment is due at maturity.

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

Promissory Notes.  We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements.  The below promissory notes represent advances to fund our working capital requirements. There can be no assurance that LEH and its affiliates will continue to fund our working capital requirements.

● June LEH Note – In March 2017, Blue Dolphin entered a promissory note with LEH in the original principal amount of $440,815 (the “March LEH Note”).  In June 2017, the March LEH Note was amended and restated to increase the amount by $2,043,482 (the “June LEH Note”).  Interest under the June LEH Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  The June LEH Note has a maturity date of January 2019.  Under the June LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to LEH under the June LEH Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.  At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to LEH under the June LEH Note and a previous promissory note, respectively, was $0. The balances under the notes were settled with amounts owed to us by LEH.

● March Ingleside Note – In March 2017, a promissory note between Blue Dolphin and Ingleside was amended and restated (the “March Ingleside Note”) to increase the principal amount by $473,445 and extend the maturity date to January 2019. Interest under the March Ingleside Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  Under the March Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to Ingleside under the March Ingleside Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets. At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to Ingleside under the March Ingleside Note was $1,168,748 and $722,278, respectively.

● March Carroll Note – In March 2017, a promissory note between Blue Dolphin and Jonathan Carroll was amended and restated (the “March Carroll Note”) to increase the principal amount by $183,030, revise the payment terms to reflect payment in cash and shares of Blue Dolphin Common Stock, and extend the maturity date to January 2019.  Interest under the March Carroll Note, which is compounded annually and accrued at a rate of 8.00%, was paid in kind and added to the outstanding balance.  Under the March Carroll Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.  Outstanding principal and accrued interest owed to Jonathan Carroll under the March Carroll Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets. At September 30, 2017 and December 31, 2016, the outstanding principal and accrued interest owed to Jonathan Carroll under the March Carroll Note was $282,907 and $592,412, respectively.

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered into on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Amended and Restated Guaranty Fee Agreements.  Pursuant to Amended and Restated Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt.  Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain loan agreements.  Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets.  Amounts expensed related to Amended and Restated Guarantee Fee Agreements are reflected within interest and other expense in our consolidated statements of operations.  (See “Note (10) Long-Term Debt, Net” for further discussion related to these guaranty fee agreements.)

Financial Statements Impact.

Consolidated Balance Sheets.  Accounts payable, related party to LMT associated with the Tolling Agreement was $823,200 and $369,600 at September 30, 2017 and December 31, 2016, respectively.  Long-term debt, related party associated with the LEH Loan Agreement, June LEH Note, March Ingleside Note, and March Carroll Note as of the dates indicated was as follows:

	September 30,			December 31,
	2017			2016
LEH	$	4,000,000		$	4,000,000
Ingleside		1,168,748			722,278
Jonathan Carroll		282,907			592,412
		5,451,655			5,314,690
Less: Long-term debt, related party,
current portion		(4,000,000	)		(500,000	)
	$	1,451,655		$	4,814,690

Accrued interest associated with the LEH Loan Agreement was $728,889 and $243,556 at September 30, 2017 and December 31, 2016, respectively.

Consolidated Statements of Operations.  Related party revenue from LEH associated with:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Jet fuel sales	$	20,802,789	$	14,536,997	$	56,360,756	$	23,449,071
Jet fuel storage fees		56,386		426,000		675,000		750,000
HOBM sales		-		-		3,425,455		-
	$	20,859,175	$	14,962,997	$	60,461,211	$	24,199,071

Related party cost of goods sold associated with the Tolling Agreement with LMT totaled $151,200 and $0 for the three months ended September 30, 2017 and 2016; related party cost of goods sold for the nine months ended September 30, 2017 and 2016 totaled $453,600 and $0.

Related party refinery operating expenses associated with the Amended and Restated Operating Agreement with LEH and the Amended and Restated Tank Lease Agreement with Ingleside for the periods indicated were as follows:

	Three Months Ended September 30,
	2017				2016
	Amount		Per bbl		Amount		Per bbl
LEH	$	1,758,005	$	1.53	$	3,028,646	$	2.66
Ingleside		-		-		125,000		0.11
	$	1,758,005	$	1.53	$	3,153,646	$	2.77

	Nine Months Ended September 30,
	2017				2016
	Amount		Per bbl		Amount		Per bbl
LEH	$	6,222,771	$	1.93	$	8,618,409	$	2.84
Ingleside		-		-		850,000		0.28
	$	6,222,771	$	1.93	$	9,468,409	$	3.12

For the three months ended September 30, 2017, refinery operating expenses per bbl decreased compared to the three months ended September 30, 2016 due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement. The Amended and Restated Operating Agreement was effective in April 2017.

For the nine months ended September 2017, refinery operating expenses per bbl decreased compared to the nine months ended September 30, 2017 due to the revised cost-plus expense reimbursement structure as noted above.  In addition, refinery operating expenses per bbl were higher during the nine months ended September 30, 2016 due to significant refinery downtime.

Interest expense associated with the LEH Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
LEH	$	201,361	$	80,000	$	643,046	$	80,000
Jonathan Carroll		165,089		172,300		499,184		522,931
	$	366,450	$	252,300	$	1,142,230	$	602,931

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9. Accrued Expenses and Other Current Liabilities

9 Months Ended

Sep. 30, 2017

Disclosure Text Block Supplement [Abstract]

Accrued Expenses and Other Current Liabilities

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

	September 30,		December 31,
	2017		2016
Unearned revenue	$	708,567	$	408,770
Board of director fees payable		203,929		136,429
Customer deposits		109,029		450,000
Property taxes		99,236		4,694
Excise and income taxes payable		60,692		24,187
Other payable		38,621		189,719
Insurance		-		67,783
	$	1,220,074	$	1,281,582

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10. Long-Term Debt, Net

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Long-Term Debt, Net

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

	September 30,			December 31,
	2017			2016
First Term Loan Due 2034 (in default)	$	23,382,570		$	23,924,607
Second Term Loan Due 2034 (in default)		9,553,728			9,729,853
Notre Dame Debt		4,977,953			1,300,000
Term Loan Due 2017		-			184,994
Capital Leases		8,427			135,879
	$	37,922,678		$	35,275,333
Less: Current portion of long-term debt, net		(35,756,045	)		(31,712,336	)
Less: Unamortized debt issue costs		(2,166,633	)		(2,262,997	)
	$	-		$	1,300,000

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

	September 30,			December 31,
	2017			2016
First Term Loan Due 2034 (in default)	$	1,673,545		$	1,673,545
Second Term Loan Due 2034 (in default)		767,673			767,673
Less: Accumulated amortization		(274,585	)		(178,221	)
	$	2,166,633		$	2,262,997

Amortization expense associated with long-term debt, net, which is included in interest expense, was $32,121 and $32,121 for the three months ended September 30, 2017 and 2016, respectively.  Amortization expense was $96,363 and $96,364 for the nine months ended September 30, 2017 and 2016, respectively.

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

	June 30,			December 31,
	2017			2016
Notre Dame Debt	$	1,846,964		$	1,691,383
LEH Loan Agreement (related party)		728,889			243,556
Second Term Loan Due 2034 (in default)		47,635			44,984
First Term Loan Due 2034 (in default)		35,875			33,866
Capital Leases		423			1,165
Term Loan Due 2017		-			185
		2,659,786			2,015,139
Less:  Interest payable, current portion		(2,659,786	)		(323,756	)
Long-term interest payable, net of current portion	$	-		$	1,691,383

Related Party.  See “Note (8) Related Party Transactions” for additional disclosures with respect to related party long-term debt.

First Term Loan Due 2034 (In Default). LE has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender.  The loan agreement is for a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”).  The First Term Loan Due 2034 matures in June 2034, has a current monthly payment of principal and interest of $198,786, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As described elsewhere in this Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the first Term Loan Due 2034.  LE also failed to replenish a payment reserve account as required.  The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 in light of the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement.  Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws.  (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LE entered a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the First Term Loan Due 2034.  Effective in April 2017, the Guaranty Fee Agreement associated with the First Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  For the three months ended September 30, 2017 and 2016, guaranty fees related to the First Term Loan Due 2034 totaled $117,214 and $121,048, respectively. For the nine months ended September 30, 2017 and 2016, guaranty fees related to the First Term Loan Due 2034 totaled $354,286 and $365,420, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.  LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034.  (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll)

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

Second Term Loan Due 2034 (In Default). LRM has a 2015 loan agreement and related security agreement with Veritex as administrative agent and lender.  The loan agreement is for a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”).  The Second Term Loan Due 2034 matures in December 2034, has a current monthly payment of principal and interest of $74,111, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As described elsewhere in this Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034.  In addition to existing or potential events of default related to the Final Arbitration Award, at September 30, 2017, LRM was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the Second Term Loan Due 2034.  The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available.  Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval.  However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement.  Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition and results of operations and likely would require us to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.)

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034.  Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  For the three months ended September 30, 2017 and 2016, guaranty fees related to the Second Term Loan Due 2034 totaled $47,874 and $49,094, respectively.  For the nine months ended September 30, 2017 and 2016, guaranty fees related to the Second Term Loan Due 2034 totaled $144,487 and $148,261, respectively.  Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.   LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034.  (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

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

Notre Dame Debt. LE entered a loan with Notre Dame Investors, Inc. as evidenced by a promissory note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt matures in January 2018, and accrues interest at a rate of 16.00%.

Pursuant to a Sixth Amendment to the Notre Dame Debt , entered into on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended to increase the principal amount by $3,677,953 (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 $3,648,742 in accordance with the GEL Letter Agreement.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt.  Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Veritex as holder of the First Term Loan Due 2034.

Term Loan Due 2017. LRM had a 2014 loan and security agreement with Veritex for a term loan facility in the principal amount of $2.0 million (the “Term Loan Due 2017”).  The Term Loan Due 2017 was amended in March 2015, pursuant to a Loan Modification Agreement (the “March Loan Modification Agreement”).  Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due date was extended to March 2017.  Pursuant to the March Loan Modification Agreement, the Term Loan Due 2017 had a monthly principal payment of $61,665 plus interest. The Term Loan Due 2017 was paid off in March 2017.

As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he received a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Term Loan Due 2017.  Effective in April 2017, the Guaranty Fee Agreement associated with the Term Loan Due 2017 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock.  (Guaranty Fee Agreements associated with the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017 are collectively referred to in this Quarterly Report as the “Amended and Restated Guaranty Fee Agreements”).  For the three months ended September 30, 2017 and 2016, guaranty fees related to the Term Loan Due 2017 totaled $0 and $2,158, respectively. For the nine months ended September 30, 2017 and 2016, guaranty fees related to the Term Loan Due 2017 totaled $411 and $9,250, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

Capital Leases. LRM entered a 36-month build-to-suit capital lease in August 2014 for the purchase of new boiler equipment for the Nixon Facility.  The equipment, which was delivered in December 2014, was added to construction in progress.  Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease, which requires a quarterly payment in the amount of $44,258, is guaranteed by Blue Dolphin.

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

	September 30,		December 31,
	2017		2016
Boiler equipment	$	538,598	$	538,598
Less:  accumulated depreciation		-		-
	$	538,598	$	538,598

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11. Asset Retirement Obligations

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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

Pipelines and Facilities and Oil and Gas Properties.  We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We depreciate the amount added to property and equipment and recognize accretion expense relating to the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

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

	September 30,			December 31,
	2017			2016
Asset retirement obligations, at the beginning of the period	$	2,027,639		$	1,985,864
Liabilities settled		(445	)		(70,969	)
Accretion expense		215,532			112,744
		2,242,726			2,027,639
Less:  asset retirement obligations, current portion		(17,065	)		(17,510	)
Long-term asset retirement obligations, at the end of the period	$	2,225,661		$	2,010,129

Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability.  At September 30, 2017 and December 31, 2016, we recognized $445 and $70,969, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability.  For the three and nine months ended September 30, 2017 and 2016, we recognized $0 in abandonment expense.

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12. Treasury Stock

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Treasury Stock

At September 30, 2017 and December 31, 2016, we had 0 and 150,000 shares of treasury stock, respectively.  In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

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13. Concentration of Risk

9 Months Ended

Sep. 30, 2017

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, 2017 and December 31, 2016, we had cash balances (including restricted cash) of more than the FDIC insurance limit per depositor in the amount of $1,183,652 and $5,372,689, respectively.

Key Supplier.

We purchased light crude oil and condensate for the Nixon Facility from GEL pursuant to the Crude Supply Agreement.  As discussed elsewhere in this Quarterly Report, we ceased purchases of crude oil and condensate from GEL under the Crude Supply Agreement in November 2016.  (See “Part I, Item 1 Financial Statements – Note (18) Commitments and Contingencies – Legal Matters” in this Quarterly Report for disclosures related to the Crude Supply Agreement, the contract-related dispute with GEL, and the Final Arbitration Award.)

We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company.  This new supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future.  However, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.  The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts and crude oil and condensate from our current supplier or otherwise.

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, 2017, we had 4 customers that accounted for approximately 84% 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, 2017, these 4 customers represented approximately $1.5 million in accounts receivable.  LEH represented approximately $1.1 million in accounts receivable.

For the three months ended September 30, 2016, we had 4 customers that accounted for approximately 70% of our refined petroleum product sales. LEH was one of these 4 significant customers and accounted for approximately 27% of our refined petroleum product sales.  At September 30, 2016, these 4 customers represented approximately $6.7 million in accounts receivable.  LEH represented approximately $2.9 million in accounts receivable.

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

For the nine months ended September 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum product sales.  LEH was one of these 4 significant customers and accounted for approximately 19% of our refined petroleum product sales. At September 30, 2016, these 4 customers represented approximately $5.5 in accounts receivable.  LEH represented approximately $2.9 million in accounts receivable.

LEH purchases our jet fuel and resells the jet fuel to a government agency.  (See “Note (8) Related Party Transactions” for additional disclosures related to our sale of jet fuel to LEH under the Jet Fuel Sales Agreement and the associated storage of LEH’s purchased jet fuel under the Terminal Services Agreement.)

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 began exporting some of our low-sulfur diesel to Mexico during the second quarter of 2016.  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,
	2017				2016				2017				2016
LPG mix	$	-	0.0	%	$	237,009	0.4	%	$	120,542	0.1	%	$	621,313	0.5	%
Naphtha		14,266,056	21.6	%		11,870,484	22.0	%		41,282,969	24.9	%		28,183,809	22.3	%
Jet fuel		20,802,789	31.5	%		15,104,900	28.0	%		56,360,757	32.8	%		41,150,686	32.5	%
HOBM		17,011,443	25.7	%		14,206,759	26.4	%		38,580,236	19.9	%		25,259,753	20.0	%
Reduced Crude		-	0.0	%		-	0.0	%		-	0.0	%		3,791,919	3.0	%
AGO		14,052,671	21.2	%		12,532,141	23.2	%		38,323,113	22.3	%		27,539,236	21.7	%
	$	66,132,959	100.0	%	$	53,951,293	100.0	%	$	174,667,617	100.0	%	$	126,546,716	100.0	%

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14. Leases

9 Months Ended

Sep. 30, 2017

Leases, Operating [Abstract]

Leases

Our company headquarters are in downtown Houston, Texas.  We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease had a 10-year term expiring in September 2017, but we extended the lease through December 2017.  We are currently exploring our leasing options. Rent expense is recognized on a straight-line basis.  For the three months ended September 30, 2017 and 2016, rent expense totaled $31,681 and $33,251, respectively.  For the nine months ended September 30, 2017 and 2016, rent expense totaled $107,853 and $92,966, respectively.

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15. Income Taxes

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Tax Benefit.  For the three months ended September 30, 2017 and 2016, we recognized an income tax benefit of $0 and $1,034,798 respectively. For the nine months ended September 30, 2017 and 2016, we recognized an income tax benefit of $0 and $3,735,040, respectively.

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 Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, relating to a series of private placements, and in 2012, because of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income.  In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $16.3 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of $638,196 per year.  Unused portions of the annual use limitation amount may be used in subsequent years.  As a result of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused.  NOL carryforwards that were generated after the 2012 ownership change are not subject to an annual use limitation under IRC Section 382 and may be used for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change.

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

	Net Operating Loss Carryforward
	Pre-Ownership Change		Post-Ownership Change		Total
Balance at December 31, 2015	$	9,614,449	$	9,616,941	$	19,231,390
Net operating losses		-		13,945,128		13,945,128
Balance at December 31, 2016	$	9,614,449	$	23,562,069	$	33,176,518
Net operating losses		-		6,469,611		6,469,611
Balance at September 30, 2017	$	9,614,449	$	30,031,680	$	39,646,129

Deferred Tax Assets and Liabilities.  At September 30, 2017 and December 31, 2016, we had $0 of net deferred tax assets available for future use.  Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:

	September 30,			December 31,
	2017			2016
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	15,750,006		$	13,550,338
Accrued arbitration award payable		6,674,017			-
Start-up costs (Nixon Facility)		1,270,361			1,373,363
Asset retirement obligations liability/deferred revenue		780,249			717,751
AMT credit and other		224,647			266,522
Total deferred tax assets		24,699,280			15,907,974
Deferred tax liabilities:
Basis differences in property and equipment		(6,762,850	)		(5,895,943	)
Total deferred tax liabilities		(6,762,850	)		(5,895,943	)
		17,936,430			10,012,031
Valuation allowance		(17,936,430	)		(10,012,031	)
Deferred tax assets, net	$	-		$	-

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, 2017 and December 31, 2016, management determined that cumulative losses incurred over the prior three-year period provided significant objective evidence that limited the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of September 30, 2017 and December 31, 2016.

Uncertain Tax Positions. We adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2013, or after and by the state of Texas for tax years ending December 31, 2012, or after.  We believe there are no uncertain tax positions for both federal and state income taxes.

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16. Earnings Per Share

9 Months Ended

Sep. 30, 2017

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,
	2017		2016			2017			2016
Net income (loss)	$	3,945,519	$	(1,938,551	)	$	(23,297,713	)	$	(7,250,371	)
Basic and diluted income per share	$	0.36	$	(0.19	)	$	(2.19	)	$	(0.69	)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,818,371		10,464,715			10,644,654			10,460,849

Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three and nine months ended September 30, 2017 and 2016 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

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17. Inventory Risk Management

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Inventory Risk Management

During 2017, we began selling all our jet fuel immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure.  Previously, Genesis/GEL used commodity futures contracts to mitigate the volatile change in value for our crude oil and refined petroleum products inventory.

When active, the fair value of commodity futures contracts was reflected in our consolidated balance sheets and the related net gain or loss was recorded within cost of refined products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) were considered to determine the fair values for marking to market the financial instruments at each period end.  Commodity transactions were executed to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors.

At September 30, 2017, we had no futures contracts of refined petroleum products and crude oil and condensate that were entered as economic hedges.  We also had no derivative instruments that were reported in our consolidated balance sheets at September 30, 2017 and December 31, 2016.

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016: 

		Gain (Loss) Recognized
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives	Statements of Operations Location		2017		2016		2017		2016
Commodity contracts	Cost of refined products sold	$	—	$	770,838	$	—	$	(2,588,734	)

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18. Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Amended and Restated Guaranty Fee Agreements.  Pursuant to Amended and Restated Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt.  Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain loan agreements.  Amounts owed to Jonathan Carroll under Amended and Restated Guaranty Fee Agreements are reflected within long-term debt, related party, net of current portion in our consolidated balance sheets.  Amounts expensed related to Amended and Restated Guarantee Fee Agreements are reflected within interest and other expense in our consolidated statements of operations.  (See “Note (10) Long-Term Debt, Net” for further discussion related to these guaranty fee agreements.)

Financial Statements Impact.

Consolidated Balance Sheets.  Accounts payable, related party to LMT associated with the Tolling Agreement was $823,200 and $369,600 at September 30, 2017 and December 31, 2016, respectively.  Long-term debt, related party associated with the LEH Loan Agreement, June LEH Note, March Ingleside Note, and March Carroll Note as of the dates indicated was as follows:

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

Amended and Restated Operating Agreement. See “Note (8) Related Party Transactions” for additional disclosures related to the Amended and Restated Operating Agreement.

Financing Agreements. See “Note (10) Long-Term Debt, Net” for additional disclosures related to financing agreements.

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

Nixon Facility Expansion. We have made and continue to make capital and efficiency improvements to the Nixon Facility. Therefore, we incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and completion of petroleum storage tanks.

Supplemental Pipeline Bonds. In August 2015, we received a letter from the Bureau of Ocean Energy Management (the “BOEM”) requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In July 2016, the BOEM issued Notice to Lessees (“NTL”) No. 2016-N01 (Requiring Additional Security), which changes the way that lessees and rights-of-way holders demonstrate financial strength and reliability to plug and abandon wells, as well as decommission and remove platforms and pipelines at the end of production or service activities. The NTL, which changed an earlier supplemental waiver process to a self-insurance model, became effective in September 2016. Pursuant to the NTL, the BOEM requested that lessees submit any relevant information needed for an overall financial review of the lessees account.  The BOEM indicated that it would use this information to evaluate a lessees’ ability to carry out its obligations and determine whether, and/or how much self-insurance a lessee can use.

In October 2016, we received a letter from the BOEM summarizing the amount required as additional security on our existing pipeline rights-of-way.  The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental pipeline bonds or acceptable financial reassurance of approximately $4.6 million.  At September 30, 2017 and December 31, 2016, we maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM.  Of the five (5) pipeline rights-of-ways reflected in the BOEM’s October 2016 letter:

(i)   the pipeline associated with one (1) right-of-way was decommissioned in 1997, and

(ii)   the pipelines associated with three (3) rights-of-way (Segment Nos. 15635, 13101, and 9428) have been approved for decommissioning by the Bureau of Safety and Environmental Enforcement (the “BSEE”); decommissioning of Segment No. 9428 also requires approval by the U.S. Army Corps of Engineers, which has not yet been granted.

There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way.  If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

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19. Subsequent Events

9 Months Ended

Sep. 30, 2017

Subsequent Events [Abstract]

Subsequent Events

Amended GEL Letter Agreement.  As previously disclosed, on November 1, 2017, LE and GEL extended the date through which GEL has the right to terminate the GEL Letter Agreement to November 28, 2017.  For additional information regarding the Final Arbitration Award, the GEL Letter Agreement, the Amended GEL Letter Agreement, and their potential effects on our business, financial condition and results of operations, see “Note (1) Organization – Going Concern” and “Note (10) Long-Term Debt, Net.”

Debt Assumption Agreement. On September 18, 2017, LEH paid, on LE’s behalf, certain obligations totaling $3,648,742 to GEL in connection with the GEL Arbitration and the GEL Letter Agreement. In exchange for such payments, LE agreed to assume $3,677,953 of LEH’s existing indebtedness pursuant to the Debt Assumption Agreement, entered into on November 14, 2017 and made effective September 18, 2017, by and among LE, LEH and John H. Kissick.

Sixth Amendment to Notre Dame Debt. Pursuant to a Sixth Amendment to the Notre Dame Debt, entered into on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended by the Additional Principal. The Additional Principal was used to make payments to GEL in the amount of $3,648,742 in connection with the GEL Letter Agreement to reduce the balance of the Final Arbitration Award.

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3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates. We have made several estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. We believe our current estimates are reasonable and appropriate, however, actual results could differ from those estimated.

Cash and Cash Equivalents

Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents were $44,931 at September 30, 2017 compared to cash and cash equivalents of $1,152,628 at December 31, 2016.

Restricted Cash

Restricted Cash. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies.  Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks. At September 30, 2017, total restricted cash was $1,650,910, comprised of restricted cash (current portion) totaling $1,500,380 and restricted cash, noncurrent totaling $150,530.  At December 31, 2016, total restricted cash was $4,930,140, comprised of restricted cash (current portion) totaling $3,347,835 and restricted cash, noncurrent totaling $1,582,305 (See “Note (10) Long-Term Debt, Net” for additional disclosures related to our loan agreements with Veritex.)

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts. Our accounts receivable consists of customer obligations due in the ordinary course of business.  Since we have a small number of customers with individually large amounts due on any given date, we evaluate potential and existing customers’ financial condition, credit worthiness, and payment history to minimize credit risk. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods. If necessary, we establish an allowance for doubtful accounts to estimate the amount of probable credit losses.  Allowance for doubtful accounts totaled $0 both at September 30, 2017 and December 31, 2016.

Inventory

Inventory. Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals.  Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs.  If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold.  (See “Note (6) Inventory” for additional disclosures related to our inventory.)

Property and Equipment

Property and Equipment.

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

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets for any period 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”) 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.  However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines.

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

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

(See “Note (7) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)

Intangibles - Other

Intangibles – Other. Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name.  At September 30, 2017 and December 31, 2016, trade name totaled $303,346. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2016. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2016.

Debt Issue Costs

Debt Issue Costs. We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability.  (See “Note (10) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) 

Revenue Recognition

Revenue Recognition.

Refined Petroleum Products Revenue. Revenue from the sale of refined petroleum products is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Rental Revenue. We lease petroleum storage tanks to both related parties and third-parties.  Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement.  Tank rental revenue is recognized on a straight-line basis as earned.

Easement Revenue. Revenue from land easement fees was associated with a Master Easement Agreement between BDPL and FLNG Land II, Inc., a Delaware corporation (“FLNG”).  Easement revenue was recognized monthly as earned and was included in other income.  In February 2017, BDPL sold approximately 15 acres of property located in Brazoria County Texas to FLIQ Common Facilities, LLC, an affiliate of FLNG.  In conjunction with the sale of real estate, the Master Easement Agreement was terminated.

Pipeline Transportation Revenue. Revenue from our pipeline operations was derived from fee-based contracts and was typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue was recognized when volumes were physically delivered for the customer through the pipeline.  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.  (See “Note (4) Business Segment Information” for further discussion related to pipeline transportation revenue.)

Income Taxes

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

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that a portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.  A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2016. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2016.

FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition.  (See “Note (15) Income Taxes” for further information related to income taxes.)

Impairment or Disposal of Long-Lived Assets

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.

Asset Retirement Obligations

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

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

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations.  Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.  (See “Note (11) Asset Retirement Obligations” for additional information related to our AROs.)

Computation of Earnings Per Share

Computation of Earnings Per Share. We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases.  (See “Note (16) Earnings Per Share” for additional information related to EPS.)

Treasury Stock

Treasury Stock. We accounted for treasury stock under the cost method.  In May 2017, our treasury stock was re-issued.  The net change in share price after acquisition of the treasury stock was recognized as a component of additional paid-in-capital in our consolidated balance sheets.  (See “Note (12) Treasury Stock” for additional disclosures related to treasury stock.)

New Pronouncements Adopted

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

ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (A Consensus of the FASB Emerging Issues Task Force). In November 2016, FASB issued ASU 2016-18, which requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. We adopted this accounting pronouncement effective December 31, 2016. Accordingly, our consolidated statement of cash flows for the nine months ended September 30, 2016 was changed to combine restricted cash with cash and cash equivalents.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11, which requires an entity to measure inventory at the lower of cost or net realizable value.  We adopted this accounting pronouncement effective January 1, 2017.  The adoption of ASU 2015-11 did not have a significant impact on our consolidated financial statements.

New Pronouncements Issued but Not Yet Effective

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

ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.  In January 2017, FASB issued ASU 2017-04.  This guidance simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test.  For public business entities that are SEC filers, the amendments in ASU 2017-04 are effective for the annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019.  ASU 2017-04 should be applied prospectively, and early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.  We do not expect adoption of this guidance to have a significant impact on our consolidated balance sheets.

ASU 2016-02,Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2014-09, Revenue from Contracts with Customers.  In May 2014, FASB issued ASU 2014-09 and has since amended the standard with ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date; ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net); ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing; ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update); ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients; and ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.  These standards replace existing revenue recognition rules with a single comprehensive model to use in accounting for revenue arising from contracts with customers.  We are evaluating the impact that adoption of these ASU’s will have 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.

Reclassification

Reclassification.  Effective January 1, 2017, we reclassified amounts associated with our Pipeline Transportation operations to Corporate and Other.  (See “Note (4) Business Segment Information” for disclosures related to Corporate and Other.)

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4. Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Business segment reporting

	Three Months Ended September 30,
	2017									2016
	Segment									Segment
	Refinery			Corporate &						Refinery			Corporate &
	Operations			Other			Total			Operations			Other			Total
Revenue from operations	$	66,899,092		$	-		$	66,899,092		$	54,668,780		$	19,526		$	54,688,306
Less: cost of operations(1)		(61,456,546	)		(466,912	)		(61,923,458	)		(55,495,575	)		(367,915	)		(55,863,490	)
Other non-interest income(2)		-			-			-			-			156,396			156,396
Less: JMA Profit Share(3)		-			-			-			(965,627	)		-			(965,627	)
EBITDA(4)	$	5,442,546		$	(466,912	)				$	(1,792,422	)	$	(191,993	)
Depletion, depreciation and
amortization								(455,437	)								(504,719	)
Interest expense, net								(574,678	)								(484,215	)
Income (loss) before income taxes								3,945,519									(2,973,349	)
Income tax benefit								-									1,034,798
Net income (loss)							$	3,945,519								$	(1,938,551	)
Capital expenditures	$	538,801		$	-		$	538,801		$	4,191,077		$	-		$	4,191,077
Identifiable assets	$	70,791,236		$	2,068,269		$	72,859,505		$	85,585,499		$	10,816,664		$	96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased. (See “Note (1) Organization - Going Concern - Final Arbitration Award” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

	Nine Months Ended September 30,
	2017									2016
	Segment									Segment
	Refinery			Corporate &						Refinery			Corporate &
	Operations			Other			Total			Operations			Other			Total
Revenue from operations	$	176,841,172		$	-		$	176,841,172		$	128,171,177		$	71,865		$	128,243,042
Less: cost of operations(1)		(197,706,434	)		(1,293,162	)		(198,999,596	)		(135,452,537	)		(1,078,910	)		(136,531,447	)
Other non-interest income(2)		-			-			-			(392,062	)		-			(392,062	)
Less: JMA Profit Share(3)		-			2,216,251			2,216,251			-			412,061			412,061
EBITDA(4)	$	(20,865,262	)	$	923,089					$	(7,673,422	)	$	(594,984	)
Depletion, depreciation and
amortization								(1,355,780	)								(1,415,519	)
Interest expense, net								(1,999,760	)								(1,301,486	)
Loss before income taxes								(23,297,713	)								(10,985,411	)
Income tax benefit								-									3,735,040
Net loss							$	(23,297,713	)							$	(7,250,371	)
Capital expenditures	$	3,428,129		$	-		$	3,428,129		$	13,857,434		$	-		$	13,857,434
Identifiable assets	$	70,791,236		$	2,068,269		$	72,859,505		$	85,585,499		$	10,816,664		$	96,402,163

(1)	Operation cost within the Refinery Operations segment includes related general and administrative expenses and the arbitration award and associated fees.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).
(2)	Other non-interest income reflects FLNG easement revenue.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased. (See “Note (1) Organization - Going Concern - Final Arbitration Award” for further discussion related to the contract-related dispute with GEL.)
(4)	EBITDA is a non-GAAP financial measure.  See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

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5. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2017

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

Prepaid balances

	September 30,		December 31,
	2017		2016
Prepaid crude oil and condensate	$	1,332,439	$	-
Prepaid insurance		298,913		248,853
Short-term tax bond		-		505,000
Prepaid exise taxes		-		292,338
	$	1,631,352	$	1,046,191

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6. Inventory (Tables)

9 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Inventory

	September 30,		December 31,
	2017		2016
Crude oil and condensate	$	1,207,865	$	26,123
AGO		910,189		143,362
HOBM		341,660		212,987
Chemicals		156,535		182,751
Naphtha		135,554		533,580
Propane		18,377		11,318
LPG mix		5,260		1,293
Jet fuel		-		964,124
	$	2,775,440	$	2,075,538

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

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Property and equipment

	September 30,			December 31,
	2017			2016
Refinery and facilities	$	51,432,434		$	50,814,309
Land		566,159			602,938
Other property and equipment		652,795			652,795
		52,651,388			52,070,042
Less:  Accumulated depletion, depreciation, and amortization		(8,041,024	)		(6,685,244	)
		44,610,364			45,384,798
Construction in progress		19,786,447			16,939,665
	$	64,396,811		$	62,324,463

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8. Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Accounts Payable, Related Party

	September 30,			December 31,
	2017			2016
LEH	$	4,000,000		$	4,000,000
Ingleside		1,168,748			722,278
Jonathan Carroll		282,907			592,412
		5,451,655			5,314,690
Less: Long-term debt, related party,
current portion		(4,000,000	)		(500,000	)
	$	1,451,655		$	4,814,690

Accrued interest Expenses

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Jet fuel sales	$	20,802,789	$	14,536,997	$	56,360,756	$	23,449,071
Jet fuel storage fees		56,386		426,000		675,000		750,000
HOBM sales		-		-		3,425,455		-
	$	20,859,175	$	14,962,997	$	60,461,211	$	24,199,071

Refinery operating expenses

	Three Months Ended September 30,
	2017				2016
	Amount		Per bbl		Amount		Per bbl
LEH	$	1,758,005	$	1.53	$	3,028,646	$	2.66
Ingleside		-		-		125,000		0.11
	$	1,758,005	$	1.53	$	3,153,646	$	2.77

	Nine Months Ended September 30,
	2017				2016
	Amount		Per bbl		Amount		Per bbl
LEH	$	6,222,771	$	1.93	$	8,618,409	$	2.84
Ingleside		-		-		850,000		0.28
	$	6,222,771	$	1.93	$	9,468,409	$	3.12

Interest expense associated with the LEH Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows: 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
LEH	$	201,361	$	80,000	$	643,046	$	80,000
Jonathan Carroll		165,089		172,300		499,184		522,931
	$	366,450	$	252,300	$	1,142,230	$	602,931

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9. Accrued Expenses and Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2017

Disclosure Text Block Supplement [Abstract]

Accrued expenses and other current liabilities

	September 30,		December 31,
	2017		2016
Unearned revenue	$	708,567	$	408,770
Board of director fees payable		203,929		136,429
Customer deposits		109,029		450,000
Property taxes		99,236		4,694
Excise and income taxes payable		60,692		24,187
Other payable		38,621		189,719
Insurance		-		67,783
	$	1,220,074	$	1,281,582

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10. Long-Term Debt, Net (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Schedule of Long Term Debt

	September 30,			December 31,
	2017			2016
First Term Loan Due 2034 (in default)	$	23,382,570		$	23,924,607
Second Term Loan Due 2034 (in default)		9,553,728			9,729,853
Notre Dame Debt		4,977,953			1,300,000
Term Loan Due 2017		-			184,994
Capital Leases		8,427			135,879
	$	37,922,678		$	35,275,333
Less: Current portion of long-term debt, net		(35,756,045	)		(31,712,336	)
Less: Unamortized debt issue costs		(2,166,633	)		(2,262,997	)
	$	-		$	1,300,000

Schedule of Debt issue costs

	September 30,			December 31,
	2017			2016
First Term Loan Due 2034 (in default)	$	1,673,545		$	1,673,545
Second Term Loan Due 2034 (in default)		767,673			767,673
Less: Accumulated amortization		(274,585	)		(178,221	)
	$	2,166,633		$	2,262,997

Accrued interest related to our long-term debt, net

	June 30,			December 31,
	2017			2016
Notre Dame Debt	$	1,846,964		$	1,691,383
LEH Loan Agreement (related party)		728,889			243,556
Second Term Loan Due 2034 (in default)		47,635			44,984
First Term Loan Due 2034 (in default)		35,875			33,866
Capital Leases		423			1,165
Term Loan Due 2017		-			185
		2,659,786			2,015,139
Less:  Interest payable, current portion		(2,659,786	)		(323,756	)
Long-term interest payable, net of current portion	$	-		$	1,691,383

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

	September 30,		December 31,
	2017		2016
Boiler equipment	$	538,598	$	538,598
Less:  accumulated depreciation		-		-
	$	538,598	$	538,598

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11. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

	September 30,			December 31,
	2017			2016
Asset retirement obligations, at the beginning of the period	$	2,027,639		$	1,985,864
Liabilities settled		(445	)		(70,969	)
Accretion expense		215,532			112,744
		2,242,726			2,027,639
Less:  asset retirement obligations, current portion		(17,065	)		(17,510	)
Long-term asset retirement obligations, at the end of the period	$	2,225,661		$	2,010,129

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13. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 2017

Risks and Uncertainties [Abstract]

Percentages of all refined petroleum products sales to total sales

	Three Months Ended September 30,								Nine Months Ended September 30,
	2017				2016				2017				2016
LPG mix	$	-	0.0	%	$	237,009	0.4	%	$	120,542	0.1	%	$	621,313	0.5	%
Naphtha		14,266,056	21.6	%		11,870,484	22.0	%		41,282,969	24.9	%		28,183,809	22.3	%
Jet fuel		20,802,789	31.5	%		15,104,900	28.0	%		56,360,757	32.8	%		41,150,686	32.5	%
HOBM		17,011,443	25.7	%		14,206,759	26.4	%		38,580,236	19.9	%		25,259,753	20.0	%
Reduced Crude		-	0.0	%		-	0.0	%		-	0.0	%		3,791,919	3.0	%
AGO		14,052,671	21.2	%		12,532,141	23.2	%		38,323,113	22.3	%		27,539,236	21.7	%
	$	66,132,959	100.0	%	$	53,951,293	100.0	%	$	174,667,617	100.0	%	$	126,546,716	100.0	%

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15. Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

NOL carryforwards

	Net Operating Loss Carryforward
	Pre-Ownership Change		Post-Ownership Change		Total
Balance at December 31, 2015	$	9,614,449	$	9,616,941	$	19,231,390
Net operating losses		-		13,945,128		13,945,128
Balance at December 31, 2016	$	9,614,449	$	23,562,069	$	33,176,518
Net operating losses		-		6,469,611		6,469,611
Balance at September 30, 2017	$	9,614,449	$	30,031,680	$	39,646,129

Deferred tax assets and deferred tax liabilities

	September 30,			December 31,
	2017			2016
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	15,750,006		$	13,550,338
Accrued arbitration award payable		6,674,017			-
Start-up costs (Nixon Facility)		1,270,361			1,373,363
Asset retirement obligations liability/deferred revenue		780,249			717,751
AMT credit and other		224,647			266,522
Total deferred tax assets		24,699,280			15,907,974
Deferred tax liabilities:
Basis differences in property and equipment		(6,762,850	)		(5,895,943	)
Total deferred tax liabilities		(6,762,850	)		(5,895,943	)
		17,936,430			10,012,031
Valuation allowance		(17,936,430	)		(10,012,031	)
Deferred tax assets, net	$	-		$	-

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16. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Earnings per share

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Net income (loss)	$	3,945,519	$	(1,938,551	)	$	(23,297,713	)	$	(7,250,371	)
Basic and diluted income per share	$	0.36	$	(0.19	)	$	(2.19	)	$	(0.69	)
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock		10,818,371		10,464,715			10,644,654			10,460,849

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17. Inventory Risk Management (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of derivative instruments

		Gain (Loss) Recognized
		Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives	Statements of Operations Location		2017		2016		2017		2016
Commodity contracts	Cost of refined products sold	$	—	$	770,838	$	—	$	(2,588,734	)

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1. Organization (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss)	$ 3,945,519	$ (1,938,551)	$ (23,297,713)	$ (7,250,371)
Net Loss per common share	$ 0.36	$ (0.19)	$ (2.19)	$ (0.69)
Improvement in net loss	$ .55		$ (1.50)
Working capital deficit current portion	$ 67,084,694		$ 67,084,694		$ 37,812,263
Working capital deficit payment of Operations	$ 27,328,649		$ 27,328,649		$ 5,599,927

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3. Significant Accounting Policies (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 44,931		$ 44,931		$ 1,152,628
Restricted cash	1,650,910		1,650,910		4,930,140
Restricted cash (current portion)	1,500,380		1,500,380		3,347,835
Restricted cash, noncurrent	150,530		150,530		1,582,305
Allowance for doubtful accounts	0		0		0
Trade name	303,346		303,346		$ 303,346
Gain on the disposal of property	$ 0	$ 0	$ 1,834,500	$ 0

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4. Business Segment Information (Details) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenue from operations		$ 66,899,092	$ 54,688,306	$ 176,841,172	$ 128,243,042
Depletion, depreciation and amortization		(32,121)	(32,121)	(96,363)	(96,364)
Income tax benefit		0	(1,034,798)	0	(3,735,040)
Net income (loss)		3,945,519	(1,938,551)	(23,297,713)	(7,250,371)
Refinery Operations [Member]
Revenue from operations		66,899,092	54,668,780	176,841,172	128,171,177
Less: cost of operations (1)	[1]	(61,456,546)	(55,495,575)	(197,706,434)	(135,452,537)
Other non-interest income (2)	[2]	0	0	0	(392,062)
Less: JMA Profit Share (3)	[3]	0	(965,627)	0	0
EBITDA (4)	[4]	5,442,546	(1,792,422)	(20,865,262)	(7,673,422)
Capital expenditures		538,801	4,191,077	3,428,129	13,857,434
Identifiable assets		70,791,236	85,585,499	70,791,236	85,585,499
Corporate and Other [Member]
Revenue from operations		0	19,526	0	71,865
Less: cost of operations (1)	[1]	(466,912)	(367,915)	(1,293,162)	(1,078,910)
Other non-interest income (2)	[2]	0	156,396	0	0
Less: JMA Profit Share (3)	[3]	0	0	2,216,251	412,061
EBITDA (4)	[4]	(466,912)	(191,993)	923,089	(594,984)
Capital expenditures		0	0	0	0
Identifiable assets		2,068,269	10,816,664	2,068,269	10,816,664
Total
Revenue from operations		66,899,092	54,688,306	176,841,172	128,243,042
Less: cost of operations (1)	[1]	(61,923,458)	(55,863,490)	(198,999,596)	(136,531,447)
Other non-interest income (2)	[2]	0	156,396	0	(392,062)
Less: JMA Profit Share (3)	[3]	0	(965,627)	2,216,251	412,061
Depletion, depreciation and amortization		(455,437)	(504,719)	(1,355,780)	(1,415,519)
Interest expense, net		(574,678)	(484,215)	(1,999,760)	(1,301,486)
Income (loss) before income taxes		3,945,519	(2,973,349)	(23,297,713)	(10,985,411)
Income tax benefit		0	1,034,798	0	3,735,040
Net income (loss)		3,945,519	(1,938,551)	(23,297,713)	(7,250,371)
Capital expenditures		538,801	4,191,077	3,428,129	13,857,434
Identifiable assets		$ 72,859,505	$ 96,402,163	$ 72,859,505	$ 96,402,163

[1] Operation cost within the Refinery Operations segment includes related general and administrative expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses).

[2] Other non-interest income reflects FLNG easement revenue.

[3] The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased. (See "Note (1) Organization - Going Concern - Final Arbitration Award" for further discussion related to the contract-related dispute with GEL.)

[4] EBITDA is a non-GAAP financial measure. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Non-GAAP Financial Measures" for additional information related to EBITDA.

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5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid crude oil and condensate	$ 1,332,439	$ 0
Prepaid insurance	298,913	248,853
Short-term tax bond	0	505,000
Prepaid exise taxes	0	292,338
Prepaid expenses, net	$ 1,631,352	$ 1,046,191

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6. Inventory (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Crude oil and condensate	$ 1,207,865	$ 26,123
AGO	910,189	143,362
HOBM	341,660	212,987
Chemicals	156,535	182,751
Naphtha	135,554	533,580
Propane	18,377	11,318
LPG mix	5,260	1,293
Jet fuel	0	964,124
Inventories, net	$ 2,775,440	$ 2,075,538

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7. Property, Plant and Equipment, Net (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 51,432,434	$ 50,814,309
Land	566,159	602,938
Other property and equipment	652,795	652,795
Property, Plant and Equipment, Gross	52,651,388	52,070,042
Less: Accumulated depletion, depreciation and amortization	(8,041,024)	(6,685,244)
Property, plant and equipment, gross	44,610,364	45,384,798
Construction in progress	19,786,447	16,939,665
Property, plant and equipment, net	$ 64,396,811	$ 62,324,463

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8. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 3,413,428	$ 2,108,298

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8. Related Party Transactions (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016	Dec. 30, 2016	Jun. 30, 2016
Prepaid operating expenses, related party	$ 5,451,655	$ 5,314,690
Less: Long-term debt - current portion, related party	(4,000,000)	(500,000)
Long-term debt - net of current portion, related party	1,451,655	4,814,690
LEH [Member]
Prepaid operating expenses, related party	4,000,000		$ 4,000,000
Ingleside [Member]
Prepaid operating expenses, related party	1,168,748			$ 722,278
Jonathan Carroll [Member]
Prepaid operating expenses, related party	$ 282,907	$ 592,412

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8. Related Party Transactions (Details 1) - LEH [Member] - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Jet fuel sales	$ 20,802,789	$ 14,536,997	$ 56,360,756	$ 23,449,071
Jet fuel storag fees	56,386	426,000	675,000	750,000
HOBM sales	0	0	3,425,455	0
Total	$ 20,859,175	$ 14,962,997	$ 60,461,211	$ 24,199,071

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8. Related Party Transactions (Details 2)	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) $ / bbl	Sep. 30, 2016 USD ($) $ / bbl	Sep. 30, 2017 USD ($) $ / bbl	Sep. 30, 2016 USD ($) $ / bbl
Refinery operating expenses, Amount | $	$ 1,758,005	$ 3,153,646	$ 6,222,771	$ 9,468,409
Refinery operating expenses, Per bbl | $ / bbl	1.53	2.77	1.93	3.12
LEH [Member]
Refinery operating expenses, Amount | $	$ 1,758,005	$ 3,028,646	$ 6,222,771	$ 8,618,409
Refinery operating expenses, Per bbl | $ / bbl	1.53	2.66	1.93	2.84
Ingleside [Member]
Refinery operating expenses, Amount | $	$ 0	$ 125,000	$ 0	$ 850,000
Refinery operating expenses, Per bbl | $ / bbl	0.00	.11	0.00	.28

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8. Related Party Transactions (Details 3) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Interest expenses under loan and guarantee, related party	$ 366,450	$ 252,300	$ 1,142,230	$ 602,931
LEH [Member]
Interest expenses under loan and guarantee, related party	201,361	80,000	643,046	80,000
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	$ 165,089	$ 172,300	$ 499,184	$ 522,931

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8. Related Party Transactions (Details Narrative) - USD ($)	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016	Dec. 30, 2016	Jun. 30, 2016
Prepaid related party operating expenses	$ 5,451,655	$ 5,314,690
Outstanding principal and interest	282,904	592,412
Accounts payable, related party	823,200	369,600
Sales to LMT totaled	151,200
Accrued interest	728,889	243,556
Jonathan Carroll [Member]
Prepaid related party operating expenses	282,907	592,412
Outstanding principal and interest	592,412	592,412
Ingleside [Member]
Prepaid related party operating expenses	1,168,748			$ 722,278
Outstanding principal and interest	722,278	722,278
LEH [Member]
Prepaid related party operating expenses	4,000,000		$ 4,000,000
LEH Note [Member]
Outstanding principal and interest	$ 2,043,482	$ 0

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9. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Disclosure Text Block Supplement [Abstract]
Unearned revenue	$ 708,567	$ 408,770
Board of director fees payable	203,929	136,429
Customer deposits	109,029	450,000
Property taxes	99,236	4,694
Excise and income taxes payable	60,692	24,187
Other payable	38,621	189,719
Insurance	0	67,783
Accrued Expenses and Other Current Liabilities, Net	$ 1,220,074	$ 1,281,582

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10. Long-Term Debt, Net (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Principal balance outstanding	$ 37,922,678	$ 35,275,333
Less: Current portion of long-term debt, net	(35,756,045)	35,275,333
Less: Unamortized debt issue costs	(216,633)	(2,262,997)
Long term debt	0	1,300,000
First Term Loan Due 2034 [Member]
Principal balance outstanding	23,382,570	23,924,607
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,553,728	9,729,853
Notre Dame Debt [Member]
Principal balance outstanding	4,977,953	1,300,000
Term Loan Due 2017 [Member]
Principal balance outstanding	0	184,994
Capital Leases [Member]
Principal balance outstanding	$ 8,427	$ 135,879

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10. Long-Term Debt, Net (Details 1) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 1,673,545	$ 33,866
Second Term Loan Due 2034	767,673	767,673
Less: Accumulated amortization	(274,585)	(178,221)
Long term debt	$ 2,166,633	$ 2,262,997

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10 Long-Term Debt, Net (Details 2) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Long-term Debt Net Details 2
Notre Dame Debt	$ 1,846,964	$ 1,691,383
LEH Loan Agreement (related party)	728,889	243,556
Second Term Loan Due 2034	47,635	44,984
First Term Loan Due 2034	35,875	33,866
Capital leases	423	1,165
Term Loan Due 2017	0	185
Total	2,659,786	2,015,139
Less: Interest payable, current portion	(2,659,786)	(323,756)
Long term debt	$ 0	$ 1,691,383

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10. Long-Term Debt, Net (Details 3) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation	0	0
Capital lease obligation	$ 538,598	$ 538,598

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10.Long-Term Debt, Net (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amortization expense	$ 32,121	$ 32,121	$ 96,363	$ 96,364
First Term Loan Due 2034
Guaranty fees	117,214	121,048	354,286	365,420
Second Term Loan Due 2034
Guaranty fees	47,874	49,094	144,487	148,261
Term Loan Due 2017 [Member]
Guaranty fees	$ 0	$ 2,158	$ 411	$ 9,250

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11. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period			$ 2,027,639	$ 1,985,864	$ 1,985,864
Liabilities settled			(445)		(70,969)
Accretion expense	$ 71,844	$ 28,186	215,532	$ 84,558	112,744
Asset retirement obligations	2,242,726		2,242,726		2,027,639
Less: asset retirement obligations, current portion	(17,065)		(17,065)		(17,510)
Long-term asset retirement obligations, at the end of the period	$ 2,225,661		$ 2,225,661		$ 2,010,129

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11. Asset Retirement Obligations (Details Narrative) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Liabilities settled recognized	$ 445	$ 70,969

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12. Treasury Stock (Details Narrative) - shares	Sep. 30, 2017	Dec. 31, 2016
Equity [Abstract]
Treasury stock	0	150,000

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13. Concentration of Risk (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Total refined petroleum product sales	$ 66,132,959	$ 53,951,293	$ 174,667,617	$ 126,546,716
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 0	$ 237,009	$ 120,542	$ 621,313
Concentration Risk	0.00%	0.40%	0.10%	0.50%
Naphtha
Total refined petroleum product sales	$ 14,266,056	$ 11,870,484	$ 41,282,969	$ 28,183,809
Concentration Risk	21.60%	22.00%	24.90%	22.30%
Jet Fuel
Total refined petroleum product sales	$ 20,802,789	$ 15,104,900	$ 56,360,757	$ 41,150,686
Concentration Risk	31.50%	28.00%	32.80%	32.50%
HOBM
Total refined petroleum product sales	$ 17,011,443	$ 14,206,759	$ 38,580,236	$ 25,259,753
Concentration Risk	25.70%	26.40%	19.90%	20.00%
Reduced crude
Total refined petroleum product sales	$ 0	$ 0	$ 0	$ 3,791,919
Concentration Risk	0.00%	0.00%	0.00%	3.00%
AGO
Total refined petroleum product sales	$ 14,052,671	$ 12,532,141	$ 38,323,113	$ 27,539,236
Concentration Risk	21.20%	23.20%	22.30%	21.70%

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13. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Concentration Risk	100.00%	100.00%	100.00%	100.00%
FDIC insurance limit	$ 1,183,652		$ 1,183,652		$ 5,372,689
LEH [Member]
Concentration Risk	32.00%	27.00%	34.00%	19.00%
Concentration risk accounts receivable	$ 1,100,000	$ 2,900,000	$ 1,100,000	$ 2,900,000

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14. Leases (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Leases, Operating [Abstract]
Rent expense	$ 31,681	$ 33,251	$ 107,853	$ 92,966

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15. Income Taxes (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Balance	$ 33,176,518	$ 19,231,390
Net operating losses	6,469,611	13,945,128
Balance at December 31	39,646,129	33,176,518
Pre-Ownership Change [Member]
Balance	9,614,449	9,614,449
Net operating losses	0	0
Balance at December 31	9,614,449	9,614,449
Post-Ownership Change [Member]
Balance	23,562,069	9,616,941
Net operating losses	6,469,611	13,945,128
Balance at December 31	$ 30,031,680	$ 23,562,069

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15. Income Taxes (Details 1) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 15,750,006	$ 13,550,338
Accrued arbitration award payable	6,674,017	0
Start-up costs (Nixon Facility)	1,270,361	1,373,363
Asset retirement obligations liability/deferred revenue	780,249	717,751
AMT credit and other	224,647	266,522
Total deferred tax assets	24,699,280	15,907,974
Deferred tax liabilities:
Basis differences in property and equipment	(6,762,850)	(5,895,943)
Total deferred tax liabilities	(6,762,850)	(5,895,943)
Deferred tax assets, net	17,936,430	10,012,031
Valuation allowance	(17,936,430)	(10,012,031)
Deferred tax assets, net	$ 0	$ 0

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15. Income Taxes (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Tax Benefit	$ 0	$ 1,034,798	$ 0	$ 3,735,040

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16. Earnings per share (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Net income (loss)	$ 3,945,519	$ (1,938,551)	$ (23,297,713)	$ (7,250,371)
Basic and diluted income per share	$ .36	$ (.19)	$ (2.19)	$ (.69)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,818,371	10,464,715	10,644,654	10,460,849

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17. Inventory Risk Management (Details 1) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Commodity Contracts [Member]
Cost of refined products sold	$ 0	$ 770,838	$ 0	$ (2,588,734)

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18. Commitments and Contingencies (Details Narrative) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Credit and cash backed rights of way bonds issued to the BOEM	$ 900,000	$ 900,000