Blue Dolphin Energy (BDCO) 10-Q 14 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 14, 2018
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Common Stock, Shares Outstanding		10,925,513
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2,018

Consolidated Balance Sheets (Un

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

Consolidated Balance Sheets (_2

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

Consolidated Statements of Oper

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

Consolidated Statements of Cash

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

1. Organization

1. Organization	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations Structure and Management We have the following active subsidiaries: ● Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”); ● Blue Dolphin Petroleum Company, a Delaware corporation; ● Blue Dolphin Services Co., a Texas corporation (“BDSC”); ● Lazarus Energy, LLC, a Delaware limited liability company (“LE”); ● Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”); and ● Nixon Product Storage, LLC, a Delaware limited liability company (“NPS”); In June 2018, Blue Dolphin acquired 100% of the issued and outstanding membership interests of NPS from Lazarus Midstream Partners, L.P., an affiliate of LEH, pursuant to an Assignment Agreement. The assignment was accounted for as a combination of entities under common control. See “Note (5) NPS Assignment” of this Quarterly Report for further information related to the NPS assignment. See “Part I, Item 1. Business” and “Item 2. Properties” in the Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets. Going Concern ● Final Arbitration Award and Settlement Agreement – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of approximately $31.3 million. As of the date of this report, LE has paid $9.2 million to GEL towards reducing the outstanding balance of the Final Arbitration Award. After the $3.7 million initial payment to GEL in September 2017, LE has made payments to GEL at $0.5 million per month. As previously disclosed, a hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for a period of no more than 90 days after September 18, 2017 (the “Continuance Period”), to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into a Letter Agreement with GEL, effective September 18, 2017 (the “GEL Letter Agreement”), confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement. The GEL Letter Agreement was subsequently amended nine times to extend the Continuance Period through July 2018. On July 20, 2018, LE, NPS, and Blue Dolphin, together with LEH, Carroll & Company Financial Holdings, L.P. (“C&C”), and Jonathan Carroll (collectively referred to herein as the “Lazarus Parties”), entered into a Settlement Agreement with GEL (the “Settlement Agreement”), whereby GEL and the Lazarus Parties agreed to mutually release all claims against each other and to file a stipulation of dismissal with prejudice in connection with the GEL Arbitration (the “Settlement”), subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon payment by the Lazarus Parties to GEL of $10.0 million in cash (the “Settlement Payment”) and $0.5 million in cash at the end of each calendar month until the Settlement Payment is paid (the “Interim Payments”) or the Settlement Agreement is terminated. The Interim Payments will not be applied to reduce the amount of the Settlement Payment, but such payments will reduce the Final Arbitration Award. At September 30, 2018 and December 31, 2017, accrued arbitration award payable on our consolidated balance sheet was $23.1 million and $27.1 million, respectively. At the time of the Settlement, the difference between the Settlement Payment and the amount we have accrued on our consolidated balance sheet for arbitration award payable will be recognized as a gain on our consolidated statement of operations. The Settlement Agreement restricts the Lazarus Parties from taking certain actions without the prior written consent of GEL, including: (i) the incurrence of any debt not specifically excepted in the Settlement Agreement, (ii) the establishment of any liens not specifically excepted in the Settlement Agreement, (iii) the disposition of any assets other than certain ordinary course sales to unaffiliated third parties, payments to unaffiliated third-party trade creditors and scheduled debt payments, (iv) the entrance into any transactions with affiliates not specifically excepted in the Settlement Agreement, (v) the failure to pay debts generally as they become due, and (vi) the entrance into a bankruptcy, reorganization or similar proceeding. A violation of any of the restrictions in the Settlement Agreement, as well as the failure of the Lazarus Parties to make Interim Payments as they become due, will constitute an event of default under the Settlement Agreement which, subject to certain cure periods, would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award. The Lazarus Parties are exploring the possibility of obtaining a commercial loan or other financing in an aggregate principal amount equal to the Settlement Payment (the “Settlement Financing”), subject to obtaining the consent of Veritex Community Bank (“Veritex”), as lender under certain loan agreements with the Lazarus Parties and their affiliates. Under the Settlement Agreement, the Lazarus Parties are required to work in good faith and take reasonable actions necessary to obtain the Settlement Financing in accordance with the terms of the Settlement Agreement. Prior to the consummation of the Settlement Financing, the Lazarus Parties are required to: (i) cause NPS to consummate the Settlement Financing and restrict its ability to commence a bankruptcy case, (ii) assign to NPS certain tank leases that will constitute collateral for the Settlement Financing, and (iii) cause NPS to assume joint and several liability for all or a portion of the Final Arbitration Award. The failure to achieve certain milestones in connection with obtaining the Settlement Financing will constitute an event of default under the Settlement Agreement, which would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award. Simultaneously with the execution of the Settlement Agreement, Jonathan Carroll and C&C entered into a Security Agreement pursuant to which Jonathan Carroll and C&C agreed to secure up to $10.0 million of LE’s obligations under the Final Arbitration Award with a security interest in their equity in LEH. The Settlement Agreement will terminate, unless extended in writing by GEL, on December 31, 2018 if the Settlement Payment is not made on or before such date, and the Settlement Agreement may be terminated by GEL following the occurrence of an event of default under the Settlement Agreement, as described above. Pursuant to the Settlement Agreement, the parties agreed to terminate the Letter Agreement, and GEL agreed not to take any action to execute or collect on the Final Arbitration Award and to take all action necessary to continue the District Court Action until the earlier of: (i) the date on which the Settlement Payment is paid or (ii) the termination of the Settlement Agreement. Blue Dolphin can provide no assurance that the conditions necessary for consummation of the Settlement will be met. If certain conditions are not met or the Settlement Agreement is terminated, GEL may seek to enforce the Final Arbitration Award against the Lazarus Parties, in which case: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws. ● Veritex Secured Loan Agreement Event of Default – Veritex, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the Settlement Agreement. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Additionally, Veritex must ultimately approve the Settlement. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future. We can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement Agreement, any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations, and Blue Dolphin would likely be required to seek protection under bankruptcy laws. Operating Risks For the three months ended September 30, 2018, we reported a net loss of $0.9 million, or a loss of $0.09 per share, compared to net income of $3.9 million, or income of $0.36 per share, for the three months ended September 30, 2017. Net loss for the three months ended September 30, 2018 was primarily the result of lower and sometimes negative margins on refined petroleum products, while net income for the three months ended September 30, 2017 was primarily the result of favorable margins for refined petroleum products. For the nine months ended September 30, 2018, we reported net income of $0.7 million, or income of $0.07 per share, compared to a net loss of $23.3 million, or a loss of $2.19 per share, for the nine months ended September 30, 2017. The nine months ended September 30, 2017 included the net effect to our consolidated statement of operations of the Final Arbitration Award, which was an expense of $24.3 million in arbitration award and associated fees and represented an expense of $2.29 per share. Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.26 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis declined $0.03 between the periods, which was primarily the result of slightly lower margins for refined petroleum products. Execution of our business plan was hindered during the three months ended September 30, 2018 by several factors, including: ● Working Capital Deficits – We had a working capital deficit of $71.0 million at September 30, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $29.5 million at September 30, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017. ● Crude Supply – Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, and other factors, as noted above. ● Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018 LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at September 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to the Settlement Agreement with GEL, or provide future waivers of any financial covenant defaults, which would have an adverse impact on our financial position and results of operations. We are continuing aggressive actions to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability. However, there can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. If Veritex does not approve the Settlement or if the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws. For additional disclosures related to the Final Arbitration Award, the GEL Letter Agreement, the Settlement Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Quarterly Report: ● Part I, Item 1. Financial Statements, Notes to Consolidated Financial Statements: Note (9) Related Party Transactions Note (11) Long-Term Debt, Net Note (18) Commitments and Contingencies – Legal Matters ● Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: Final Arbitration Award Results of Operations Liquidity and Capital Resources ● Part II, Item 1. Legal Proceedings ● Part II, Item 1A. Risk Factors

2. Basis of Presentation

2. Basis of Presentation	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	The accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Articles 8 and 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading. The consolidated balance sheet as of December 31, 2017 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2018, or for any other period.

3. Significant Accounting Polic

3. Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management, who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements. Use of Estimates Cash and Cash Equivalents Restricted Cash Inventory Property and Equipment Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.) Intangibles – Other Debt Issue Costs Revenue Recognition We adopted the provisions of FASB ASU (defined below) 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period. Income Taxes As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At September 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.) Impairment or Disposal of Long-Lived Assets Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (12) Asset Retirement Obligations” for additional information related to our AROs.) Computation of Earnings Per Share The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.) New Pronouncements Adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) New Pronouncements Issued, Not Yet Effective ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842) ASU 2018-09, Codification Improvements ASU 2018-07, Compensation – Stock Compensation (Topic 718) ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Business Segment Information

4. Business Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Business Segment Information	We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility. Business segment information for the periods indicated (and as of the dates indicated) was as follows: Three Months Ended September 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Net revenues (excluding intercompany fees and sales) $ 94,468 $ 1,075 $ - $ 95,543 $ 66,899 $ - $ 66,899 Intercompany fees and sales (873 ) 873 - - - - - Operation costs and expenses(1) Cost of materials and other (92,571 ) - - (92,571 ) (58,786 ) - (58,786 ) Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below) (1,085 ) (624 ) (94 ) (1,803 ) (1,758 ) (140 ) (1,898 ) Segment contribution margin $ (61 ) $ 1,324 $ (94 ) $ 1,169 $ 6,355 $ (140 ) $ 6,215 General and administrative expenses (375 ) (65 ) (489 ) (929 ) (913 ) (327 ) (1,240 ) Depreciation and amortization (432 ) (46 ) - (478 ) (452 ) (3 ) (455 ) Interest and other non-operating expenses, net (742 ) (574 ) Income (loss) before income taxes (980 ) 3,946 Income tax benefit 43 - Net income (loss) $ (937 ) $ 3,946 Capital expenditures $ 372 $ 223 $ - $ 595 $ 539 $ - $ 539 Identifiable assets $ 51,816 $ 19,425 $ 926 $ 72,167 $ 70,792 $ 2,068 $ 72,860 (1) Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). Nine Months Ended September 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Net revenues (excluding intercompany fees and sales) $ 254,245 $ 2,659 $ - $ 256,904 $ 176,842 $ - $ 176,842 Intercompany fees and sales (2,419 ) 2,419 - - - - - Operation costs and expenses(1) Cost of materials and other (244,380 ) - - (244,380 ) (189,525 ) - (189,525 ) Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below) (3,698 ) (2,092 ) (338 ) (6,128 ) (6,223 ) (399 ) (6,622 ) Segment contribution margin $ 3,748 $ 2,986 $ (338 ) $ 6,396 $ (18,906 ) $ (399 ) $ (19,305 ) General and administrative expenses (929 ) (156 ) (1,192 ) (2,277 ) (1,960 ) (894 ) (2,854 ) Depreciation and amortization (1,258 ) (138 ) - (1,396 ) (1,348 ) (8 ) (1,356 ) Interest and other non-operating income (expenses)(2) (2,235 ) 217 Income (loss) before income taxes 488 (23,298 ) Income tax benefit 260 - Net income (loss) $ 748 $ (23,298 ) Capital expenditures $ 1,141 $ 767 $ - $ 1,908 $ 3,428 $ - $ 3,428 Identifiable assets $ 51,816 $ 19,425 $ 926 $ 72,167 $ 70,792 $ 2,068 $ 72,860 (1) Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

5. NPS Assignment

5. NPS Assignment	9 Months Ended
	Sep. 30, 2018
Nps Assignment
NPS Assignment	In June 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS, a Delaware limited liability company, from Lazarus Midstream Partners, L.P. (“Lazarus Midstream”), an affiliate of LEH, pursuant to an Assignment Agreement. The transaction represents transfer of a vacant shell entity owned by Lazarus Midstream to Blue Dolphin for the nominal fee of $10.00. The assignment of interest facilitates the Lazarus Parties exploring the possibility of obtaining the Settlement Financing under the Settlement Agreement. The assignment was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of NPS were transferred at their carrying amounts at the date of transfer and the results of operations are included for the three and nine months ended September 30, 2018. NPS did not have significant assets, liabilities or results of operations for the three and nine months ended September 30, 2017. NPS holds a leasehold interest in petroleum storage tanks at the Nixon Facility. NPS’ revenues and expenses are included in our Tolling and Terminaling business segment.

6. Prepaid Expenses and Other C

6. Prepaid Expenses and Other Current Assets	9 Months Ended
	Sep. 30, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Prepaid insurance $ 408 $ 294 Other prepaids 39 - Prepaid crude oil and condensate - 913 $ 447 $ 1,207

7. Inventory

7. Inventory	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Crude oil and condensate $ 1,571 $ 961 AGO 449 213 HOBM 256 1,558 Naphtha 234 170 Chemicals 94 162 Propane 18 17 LPG mix 5 8 $ 2,627 $ 3,089

8. Property, Plant and Equipmen

8. Property, Plant and Equipment, Net	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Refinery and facilities $ 54,210 $ 51,432 Land 566 566 Other property and equipment 747 653 55,523 52,651 Less: Accumulated depletion, depreciation, and amortization (9,892 ) (8,495 ) 45,631 44,156 Construction in progress 19,478 20,441 $ 65,109 $ 64,597 We capitalize interest cost incurred on funds used to construct property, plant, and equipment. Capitalized interest, which is recorded as part of the asset to which it relates, is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $4.2 million and $3.9 million at September 30, 2018 and December 31, 2017, respectively. We expect construction of petroleum storage tanks at the Nixon Facility to continue until year end.

9. Related Party Transactions

9. Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Blue Dolphin and certain of its subsidiaries are party to several agreements with LEH and its affiliates. Management believes that these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. Related Parties LEH Ingleside Crude, LLC (“Ingleside”) Lazarus Marine Terminal I, LLC (“LMT”) 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. Operations Related Agreements . Amended and Restated Operating Agreement Jet Fuel Sales Agreement Terminal Services Agreement Amended and Restated Tank Lease Agreement Dock Tolling Agreement Financial Agreements . BDPL Loan Agreement (In Default) The proceeds of the BDPL Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the BDPL Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the BDPL Loan Agreement is reflected in interest payable, related party, current portion in our consolidated balance sheets. Promissory Notes ● June LEH Note ● March Ingleside Note ● March Carroll Note Debt Assumption Agreement Amended and Restated Guaranty Fee Agreements Financial Statements Impact Consolidated Balance Sheets Long-term debt, related party associated with the BDPL Loan Agreement, March Ingleside Note, and the March Carroll Note as of the dates indicated was as follows: September 30, December 31, 2018 2017 (in thousands) LEH $ 4,303 $ 4,000 Ingleside 1,263 1,169 Jonathan Carroll 966 439 6,532 5,608 Less: Long-term debt, related party, current portion (6,532 ) (4,000 ) $ - $ 1,608 Accrued interest associated with the BDPL Loan Agreement was $1.4 million and $0.9 million at September 30, 2018 and December 31, 2017, respectively. Consolidated Statements of Operations Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except percent amounts) Refinery operations LEH $ 27,299 28.7 % $ 20,803 31.1 % $ 73,415 28.6 % $ 59,786 33.8 % Other customers 67,169 70.4 % 45,330 67.8 % 180,830 70.4 % 114,882 65.0 % Tolling and terminaling LEH - 0.0 % 56 0.1 % - 0.0 % 675 0.4 % Other customers 1,075 0.9 % 710 1.0 % 2,659 1.0 % 1,499 0.8 % $ 95,543 100.0 % $ 66,899 100.0 % $ 256,904 100.0 % $ 176,842 100.0 % Fees associated with the Dock Tolling Agreement with LMT totaled $0.2 million for both the three months ended September 30, 2018 and 2017. Fees associated with the Dock Tolling Agreement with LMT totaled $0.6 million for both the nine months ended September 30, 2018 and 2017. Expenses and fees associated with the Amended and Restated Operating Agreement with LEH for the periods indicated were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Amount per bbl Amount per bbl Amount per bbl Amount per bbl (in thousands, except per bbl amounts) Blue Dolphin's direct operating expenses $ 1,033 0.85 $ 1,674 1.46 $ 4,175 1.22 $ 5,927 1.84 LEH operating fee 52 0.04 84 0.07 209 0.06 296 0.09 Total refinery operating expenses $ 1,085 $ 0.89 $ 1,758 $ 1.53 $ 4,384 $ 1.28 $ 6,223 $ 1.93 For the three months ended September 30, 2018, refinery operating expenses decreased approximately $0.7 million, or $0.64 per bbl, compared to the same period a year earlier. For the nine months ended September 30, 2018, refinery operating expenses decreased approximately $1.8 million, or $0.65 per bbl, compared to the same nine-month period a year earlier. The decrease in refinery operating expenses was due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement, as well as management’s efforts to reduce spending. Interest expense associated with the BDPL Loan Agreement, the Restated Guaranty Fee Agreements, and the related-party promissory notes (the June LEH Note, the March Ingleside Note, and March Carroll Note) for the periods indicated was as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Jonathan Carroll $ 180 $ 171 $ 519 $ 521 LEH 166 164 489 542 Ingleside 25 23 96 69 $ 371 $ 358 $ 1,104 $ 1,132

10. Accrued Expenses and Other

10. Accrued Expenses and Other Current Liabilities	9 Months Ended
	Sep. 30, 2018
Disclosure Text Block Supplement [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Board of director fees payable $ 270 $ 207 Other payable 205 116 Unearned revenue 125 450 Property taxes 122 131 Customer deposits 109 109 Excise and income taxes payable 32 79 Insurance - 68 $ 863 $ 1,160

11. Long-Term Debt, Net

11. Long-Term Debt, Net	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt, Net	Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 22,663 $ 23,199 Second Term Loan Due 2034 (in default) 9,344 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 51 - $ 37,036 $ 37,679 Less: Current portion of long-term debt, net (34,988 ) (35,544 ) Less: Unamortized debt issue costs (2,038 ) (2,135 ) $ 10 $ - Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 1,674 $ 1,674 Second Term Loan Due 2034 (in default) 768 768 Less: Accumulated amortization (404 ) (307 ) $ 2,038 $ 2,135 Amortization expense was $0.03 million for both the three months ended September 30, 2018 and 2017. Amortization expense was $0.1 million for both the nine months ended September 30, 2018 and 2017. Accrued interest associated with long-term debt, net is reflected as interest payable, in default and interest payable, related party, in default in our consolidated balance sheets. Accrued interest as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,643 $ 2,046 BDPL Loan Agreement (related party, in default) 1,374 892 Second Term Loan Due 2034 (in default) 52 49 First Term Loan Due 2034 (in default) 39 40 4,108 3,027 Less: Interest payable, current portion (4,108 ) (3,027 ) Long-term interest payable, net of current portion $ - $ - Related Party First Term Loan Due 2034 (In Default) a term loan in the principal amount of $25.0 million As described elsewhere in this Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LE was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee r epayment 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) As described elsewhere in this Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at September 30, 2018, LRM was in violation of the debt service coverage ratio, the current ratio, and debt-to-net worth ratio financial covenants related to the Second Term Loan Due 2034. The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – "Going Concern" and " - Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the Second Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.05 million and $0.05 million for the three months ended September 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.1 million and $0.1 million for the nine months ended September 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million, the funds of which were used to purchase idle refinery equipment for refurbishment and use at the Nixon Facility. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Notre Dame Debt (In Default) The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Capital Leases Boiler Equipment Lease Crane Lease A summary of equipment held under long-term capital leases as of the dates indicated follows: September 30, December 31, 2018 2017 (in thousands) Crane $ 94 $ - Less: accumulated depreciation (10 ) - $ 84 $ -

12. Asset Retirement Obligation

12. Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Refinery and Facilities Pipelines and Facilities and Oil and Gas Properties Changes to our ARO liability for the periods indicated were as follows: September 30, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Liabilities settled (1 ) - Accretion expense 205 287 2,519 2,315 Less: asset retirement obligations, current portion (2,519 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ - $ -

13. Treasury Stock

13. Treasury Stock	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Treasury Stock	At September 30, 2018 and December 31, 2017, we had 0 shares of treasury stock. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

14. Concentration of Risk

14. Concentration of Risk	9 Months Ended
	Sep. 30, 2018
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier Operation of the Nixon Facility depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate on favorable terms, and we expect the supplier to continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude oil and condensate could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements. Significant Customers For the three months ended September 30, 2018, we had 4 customers that accounted for approximately 94% of refinery operations revenue. LEH, a related party, was 1 of these 4 significant customers and accounted for approximately 29% of refinery operations revenue. At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable. LEH represented approximately $0 in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.) For the three months ended September 30, 2017, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 32% of our refined petroleum product sales. At September 30, 2017, these 4 customers represented approximately $1.5 million in accounts receivable. LEH represented approximately $1.1 million in accounts receivable. For the nine months ended September 30, 2018, we had 4 customers that accounted for approximately 90% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 29% of our refined petroleum product sales. At September 30, 2018, these 4 customers represented approximately $1.3 million in accounts receivable. LEH represented approximately $0 in accounts receivable. For the nine months ended September 30, 2017, we had 3 customers that accounted for approximately 67% of our refined petroleum product sales. LEH was 1 of these 3 significant customers and accounted for approximately 34% of our refined petroleum product sales. At September 30, 2017, these 3 customers represented approximately $1.2 million in accounts receivable. LEH represented approximately $1.1 million in accounts receivable. Refined Petroleum Product Sales Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) LPG mix $ - 0.0 % $ - 0.0 % $ 3 0.0 % $ 121 0.1 % Naphtha 24,127 25.5 % 14,266 21.6 % 64,093 25.2 % 41,283 24.9 % Jet fuel 27,299 28.9 % 20,803 31.5 % 73,415 28.9 % 56,361 32.8 % HOBM 21,735 23.0 % 17,011 25.7 % 60,594 23.8 % 38,580 19.9 % AGO 21,307 22.6 % 14,053 21.2 % 56,140 22.1 % 38,323 22.3 % $ 94,468 100.0 % $ 66,133 100.0 % $ 254,245 100.0 % $ 174,668 100.0 %

15. Leases

15. Leases	9 Months Ended
	Sep. 30, 2018
Leases, Operating [Abstract]
Leases	BDSC leases our principal office space in Houston, Texas under a 2006 lease agreement. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that extended the lease period by sixty-eight (68) months expiring on August 31, 2023. Under the Lease Amendment, our base rent for 6,489 square feet is $0.01 million per month. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For both the three months ended September 30, 2018 and 2017, rent expense totaled $0.03 million. For both the nine months ended September 30, 2018 and 2017, rent expense totaled $0.1 million.

16. Income Taxes

16. Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The principal element of the Tax Cuts and Jobs Act relevant to our financial statements is a reduction in the U.S. federal corporate tax rate from 34% to 21%, effective January 1, 2018. Other provisions of the Tax Cuts and Jobs Act did not have a significant impact on our financial statements for the three and nine months ended September 30, 2018. For the three months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.04 million and $0, respectively. For the nine months ended September 30, 2018 and 2017, we recognized an income tax benefit of $0.2 million and $0, respectively. The provision for income tax benefit (expense) as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Current Federal $ 108 $ - State 43 - Deferred Impact of change in enacted tax rates - (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 260 $ - In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to Alternative Minimum Tax credits made refundable by the Tax Cuts and Jobs Act. In 2017, our effective tax rate differed from the U.S. federal statutory rate primarily due to re-measuring deferred income taxes at the new statutory tax rate and the related change of the valuation allowance over our deferred tax assets. At the date of enactment of the Tax Cuts and Jobs Act, we re-measured our deferred tax assets and liabilities using a rate of 21%, which is the rate expected to be in place when such deferred assets and liabilities are expected to reverse in the future. The re-measurement was offset by a change in our valuation allowance. This had no impact on our net deferred tax assets. The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross profit rather than on its net income, certain aspects of TMT make it like an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. For the three and nine months ended September 30, 2018 and 2017, we recognized income relating to state income tax of $0.04 million and $0, respectively. Deferred income taxes as of the dates indicated consisted of the following: September 30, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 11,814 $ 9,767 Accrued arbitration award payable 3,048 4,122 Start-up costs (crude oil and condensate processing facility) 699 763 Asset retirement obligations liability/deferred revenue 6 495 AMT credit and other 15 217 Total deferred tax assets 14,033 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,936 ) (4,415 ) Total deferred tax liabilities (4,936 ) (4,415 ) 9,097 10,950 Valuation allowance (10,538 ) (10,950 ) Deferred tax assets, net $ 108 $ - Deferred Income Taxes NOL Carryforwards NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused because of the IRC Section 382 limitation): Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses - 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses - 9,747 9,747 Balance at September 30, 2018 $ 9,614 $ 39,965 $ 49,579 Valuation Allowance

17. Earnings Per Share

17. Earnings Per Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except share and per share amounts) Net income (loss) $ (937 ) $ 3,946 $ 748 $ (23,298 ) Basic and diluted income (loss) per share $ (0.09 ) $ 0.36 $ 0.07 $ (2.19 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,818,371 10,925,513 10,644,654 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three and nine months ended September 30, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

18. Commitments and Contingenci

18. Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Matters Final Arbitration Award and Settlement Agreement Veritex Secured Loan Agreement Event of Default Other Legal Matters Amended and Restated Operating Agreement FLNG Easements Financing Agreements Guarantees Health, Safety and Environmental Matters Nixon Facility Expansion Supplemental Pipeline Bonds BDPL has initiated settlement discussions with BOEM to resolve the Separate Orders and the INCs. There can be no assurance that BOEM will: (i) accept a proposal for a reduced amount of supplemental financial assurance, (ii) not require additional supplemental pipeline bonds related to BDPL’s existing pipeline rights-of-way, and/or (iii) not impose penalties under the INCs. As a result, we are unable to predict the outcome of the discussions with BOEM or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded a liability on our consolidated balance sheet as of September 30, 2018. As of September 30, 2018 and December 31, 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or is assessed significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition.

3. Significant Accounting Pol_2

3. Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Inventory	Inventory
Property and Equipment	Property and Equipment Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)
Intangibles - Other	Intangibles – Other
Debt Issue Costs	Debt Issue Costs
Revenue Recognition	Revenue Recognition We adopted the provisions of FASB ASU (defined below) 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period.
Income Taxes	Income Taxes As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of September 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At September 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.)
Impairment or Disposal of Long-Lived Assets	Impairment or Disposal of Long-Lived Assets
Asset Retirement Obligations	Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (12) Asset Retirement Obligations” for additional information related to our AROs.)
Computation of Earnings Per Share	Computation of Earnings Per Share The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.)
New Pronouncements Adopted	New Pronouncements Adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606)
New Pronouncements Issued but Not Yet Effective	New Pronouncements Issued, Not Yet Effective ASUs 2018-11, 2018-10, and 2016-02, Leases (Topic 842) ASU 2018-09, Codification Improvements ASU 2018-07, Compensation – Stock Compensation (Topic 718) ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Business Segment Informati_2

4. Business Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Business segment reporting	Three Months Ended September 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Net revenues (excluding intercompany fees and sales) $ 94,468 $ 1,075 $ - $ 95,543 $ 66,899 $ - $ 66,899 Intercompany fees and sales (873 ) 873 - - - - - Operation costs and expenses(1) Cost of materials and other (92,571 ) - - (92,571 ) (58,786 ) - (58,786 ) Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below) (1,085 ) (624 ) (94 ) (1,803 ) (1,758 ) (140 ) (1,898 ) Segment contribution margin $ (61 ) $ 1,324 $ (94 ) $ 1,169 $ 6,355 $ (140 ) $ 6,215 General and administrative expenses (375 ) (65 ) (489 ) (929 ) (913 ) (327 ) (1,240 ) Depreciation and amortization (432 ) (46 ) - (478 ) (452 ) (3 ) (455 ) Interest and other non-operating expenses, net (742 ) (574 ) Income (loss) before income taxes (980 ) 3,946 Income tax benefit 43 - Net income (loss) $ (937 ) $ 3,946 Capital expenditures $ 372 $ 223 $ - $ 595 $ 539 $ - $ 539 Identifiable assets $ 51,816 $ 19,425 $ 926 $ 72,167 $ 70,792 $ 2,068 $ 72,860 (1) Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). Nine Months Ended September 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Net revenues (excluding intercompany fees and sales) $ 254,245 $ 2,659 $ - $ 256,904 $ 176,842 $ - $ 176,842 Intercompany fees and sales (2,419 ) 2,419 - - - - - Operation costs and expenses(1) Cost of materials and other (244,380 ) - - (244,380 ) (189,525 ) - (189,525 ) Operating expenses (excluding depreciation and amortization and general and administrative expenses presented below) (3,698 ) (2,092 ) (338 ) (6,128 ) (6,223 ) (399 ) (6,622 ) Segment contribution margin $ 3,748 $ 2,986 $ (338 ) $ 6,396 $ (18,906 ) $ (399 ) $ (19,305 ) General and administrative expenses (929 ) (156 ) (1,192 ) (2,277 ) (1,960 ) (894 ) (2,854 ) Depreciation and amortization (1,258 ) (138 ) - (1,396 ) (1,348 ) (8 ) (1,356 ) Interest and other non-operating income (expenses)(2) (2,235 ) 217 Income (loss) before income taxes 488 (23,298 ) Income tax benefit 260 - Net income (loss) $ 748 $ (23,298 ) Capital expenditures $ 1,141 $ 767 $ - $ 1,908 $ 3,428 $ - $ 3,428 Identifiable assets $ 51,816 $ 19,425 $ 926 $ 72,167 $ 70,792 $ 2,068 $ 72,860 (1) Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

6. Prepaid Expenses and Other_2

6. Prepaid Expenses and Other Current Assets (Tables)	9 Months Ended
	Sep. 30, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid balances	September 30, December 31, 2018 2017 (in thousands) Prepaid insurance $ 408 $ 294 Other prepaids 39 - Prepaid crude oil and condensate - 913 $ 447 $ 1,207

7. Inventory (Tables)

7. Inventory (Tables)	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Inventory	September 30, December 31, 2018 2017 (in thousands) Crude oil and condensate $ 1,571 $ 961 AGO 449 213 HOBM 256 1,558 Naphtha 234 170 Chemicals 94 162 Propane 18 17 LPG mix 5 8 $ 2,627 $ 3,089

8. Property, Plant and Equipm_2

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

9. Related Party Transactions (

9. Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Accounts Payable, Related Party	September 30, December 31, 2018 2017 (in thousands) LEH $ 4,303 $ 4,000 Ingleside 1,263 1,169 Jonathan Carroll 966 439 6,532 5,608 Less: Long-term debt, related party, current portion (6,532 ) (4,000 ) $ - $ 1,608
Accrued interest Expenses	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except percent amounts) Refinery operations LEH $ 27,299 28.7 % $ 20,803 31.1 % $ 73,415 28.6 % $ 59,786 33.8 % Other customers 67,169 70.4 % 45,330 67.8 % 180,830 70.4 % 114,882 65.0 % Tolling and terminaling LEH - 0.0 % 56 0.1 % - 0.0 % 675 0.4 % Other customers 1,075 0.9 % 710 1.0 % 2,659 1.0 % 1,499 0.8 % $ 95,543 100.0 % $ 66,899 100.0 % $ 256,904 100.0 % $ 176,842 100.0 %
Refinery operating expenses	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Amount per bbl Amount per bbl Amount per bbl Amount per bbl (in thousands, except per bbl amounts) Blue Dolphin's direct operating expenses $ 1,033 0.85 $ 1,674 1.46 $ 4,175 1.22 $ 5,927 1.84 LEH operating fee 52 0.04 84 0.07 209 0.06 296 0.09 Total refinery operating expenses $ 1,085 $ 0.89 $ 1,758 $ 1.53 $ 4,384 $ 1.28 $ 6,223 $ 1.93 Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Jonathan Carroll $ 180 $ 171 $ 519 $ 521 LEH 166 164 489 542 Ingleside 25 23 96 69 $ 371 $ 358 $ 1,104 $ 1,132

10. Accrued Expenses and Othe_2

10. Accrued Expenses and Other Current Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Disclosure Text Block Supplement [Abstract]
Accrued expenses and other current liabilities	September 30, December 31, 2018 2017 (in thousands) Board of director fees payable $ 270 $ 207 Other payable 205 116 Unearned revenue 125 450 Property taxes 122 131 Customer deposits 109 109 Excise and income taxes payable 32 79 Insurance - 68 $ 863 $ 1,160

11. Long-Term Debt, Net (Tables

11. Long-Term Debt, Net (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of Long Term Debt	September 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 22,663 $ 23,199 Second Term Loan Due 2034 (in default) 9,344 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 51 - $ 37,036 $ 37,679 Less: Current portion of long-term debt, net (34,988 ) (35,544 ) Less: Unamortized debt issue costs (2,038 ) (2,135 ) $ 10 $ -
Schedule of Debt issue costs	September 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 1,674 $ 1,674 Second Term Loan Due 2034 (in default) 768 768 Less: Accumulated amortization (404 ) (307 ) $ 2,038 $ 2,135
Accrued interest related to our long-term debt, net	September 30, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,643 $ 2,046 BDPL Loan Agreement (related party, in default) 1,374 892 Second Term Loan Due 2034 (in default) 52 49 First Term Loan Due 2034 (in default) 39 40 4,108 3,027 Less: Interest payable, current portion (4,108 ) (3,027 ) Long-term interest payable, net of current portion $ - $ -
Schedule of summary of equipment held under long-term capital leases	September 30, December 31, 2018 2017 (in thousands) Crane $ 94 $ - Less: accumulated depreciation (10 ) - $ 84 $ -

12. Asset Retirement Obligati_2

12. Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	September 30, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Liabilities settled (1 ) - Accretion expense 205 287 2,519 2,315 Less: asset retirement obligations, current portion (2,519 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ - $ -

14. Concentration of Risk (Tabl

14. Concentration of Risk (Tables)	9 Months Ended
	Sep. 30, 2018
Risks and Uncertainties [Abstract]
Percentages of all refined petroleum products sales to total sales	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) LPG mix $ - 0.0 % $ - 0.0 % $ 3 0.0 % $ 121 0.1 % Naphtha 24,127 25.5 % 14,266 21.6 % 64,093 25.2 % 41,283 24.9 % Jet fuel 27,299 28.9 % 20,803 31.5 % 73,415 28.9 % 56,361 32.8 % HOBM 21,735 23.0 % 17,011 25.7 % 60,594 23.8 % 38,580 19.9 % AGO 21,307 22.6 % 14,053 21.2 % 56,140 22.1 % 38,323 22.3 % $ 94,468 100.0 % $ 66,133 100.0 % $ 254,245 100.0 % $ 174,668 100.0 %

16. Income Taxes (Tables)

16. Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	September 30, December 31, 2018 2017 (in thousands) Current Federal $ 108 $ - State 43 - Deferred Impact of change in enacted tax rates - (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 260 $ -
Deferred tax assets and deferred tax liabilities	September 30, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 11,814 $ 9,767 Accrued arbitration award payable 3,048 4,122 Start-up costs (crude oil and condensate processing facility) 699 763 Asset retirement obligations liability/deferred revenue 6 495 AMT credit and other 15 217 Total deferred tax assets 14,033 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,936 ) (4,415 ) Total deferred tax liabilities (4,936 ) (4,415 ) 9,097 10,950 Valuation allowance (10,538 ) (10,950 ) Deferred tax assets, net $ 108 $ -
NOL carryforwards	Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses - 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses - 9,747 9,747 Balance at September 30, 2018 $ 9,614 $ 39,965 $ 49,579

17. Earnings Per Share (Tables)

17. Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings per share	Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands, except share and per share amounts) Net income (loss) $ (937 ) $ 3,946 $ 748 $ (23,298 ) Basic and diluted income (loss) per share $ (0.09 ) $ 0.36 $ 0.07 $ (2.19 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,818,371 10,925,513 10,644,654

1. Organization (Details Narrat

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

3. Significant Accounting Pol_3

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

4. Business Segment Informati_3

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

6. Prepaid Expenses and Other_3

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

7. Inventory (Details)

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

8. Property, Plant and Equipm_3

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

8. Property, Plant and Equipm_4

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

9. Related Party Transactions_2

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

9. Related Party Transactions_3

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

9. Related Party Transactions_4

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

9. Related Party Transactions_5

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

9. Related Party Transactions_6

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

10. Accrued Expenses and Othe_3

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

11. Long-Term Debt, Net (Detail

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

11. Long-Term Debt, Net (Deta_2

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

11. Long-Term Debt, Net (Deta_3

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

11. Long-Term Debt, Net (Deta_4

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

11. Long-Term Debt, Net (Deta_5

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

12. Asset Retirement Obligati_3

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

13. Treasury Stock (Details Nar

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

14. Concentration of Risk (Deta

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

14. Concentration of Risk (De_2

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

15. Leases (Details Narrative)

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

16. Income Taxes (Details)

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

16. Income Taxes (Details 1)

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

16. Income Taxes (Details 2)

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

16. Income Taxes (Details Narra

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

17. Earnings per share (Details

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