Blue Dolphin Energy (BDCO) 10-K 1 Apr 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Apr. 01, 2019	Jun. 30, 2018
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		10,975,514
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2018
Entity Public Float			$ 4,000,124

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 14	$ 495
Restricted cash	49	49
Accounts receivable, net	379	1,357
Accounts receivable, related party	0	653
Prepaid expenses and other current assets	1,786	1,207
Deposits	194	129
Inventory	1,510	3,089
Refundable federal income tax	108	0
Total current assets	4,040	6,979
Total property and equipment, net	64,697	64,597
Restricted cash, noncurrent	1,602	1,602
Surety bonds	230	230
Trade name	108	0
Total long-term assets	66,637	66,429
TOTAL ASSETS	70,677	73,408
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion	34,863	35,544
Long-term debt, related party, current portion	7,041	4,000
Interest payable, current portion	2,939	2,135
Interest payable, related party, current portion	1,534	892
Accounts payable	2,719	2,344
Accounts payable, related party	1,529	974
Asset retirement obligations, current portion	2,580	2,315
Accrued expenses and other current liabilities	1,571	1,160
Accrued arbitration award payable	21,128	27,128
Total current liabilities	75,904	76,492
Long-term liabilities:
Deferred revenues and expenses	0	42
Long-term debt, related party, net of current portion	0	1,608
Total long-term liabilities	0	1,650
TOTAL LIABILITIES	75,904	78,142
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,975,514 and 10,925,513 shares issued at December 31, 2018 and 2017, respectively)	110	109
Additional paid-in capital	36,936	36,907
Accumulated deficit	(42,273)	(41,750)
Total stockholders' equity	(5,227)	(4,734)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 70,677	$ 73,408

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Treasury stock, shares	0	0

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 337,038	$ 255,547
Tolling and terminaling	3,723	2,902
Total revenue from operations	340,761	258,449
COST OF GOODS SOLD
Crude oil, fuel use, and chemicals	322,297	239,740
Other conversion costs	9,639	8,693
Total cost of goods sold	331,936	248,433
Gross Profit	8,825	10,016
COST OF OPERATIONS
LEH operating fee	614	817
Other operating expenses	180	228
Arbitration award and associated fees	0	24,339
General and administrative expenses	3,272	4,022
Depletion, depreciation and amortization	1,933	1,810
Impairment of assets	0	303
Bad debt expense	0	81
Accretion of asset retirement obligations	266	287
Total cost of operations	6,265	31,887
Income (loss) from operations	2,560	(21,871)
OTHER INCOME (EXPENSE)
Easement, interest and other income	20	479
Interest and other expense	(3,363)	(2,770)
Gain on disposal of property	0	1,834
Total other income (expense)	(3,343)	(457)
Loss before income taxes	(783)	(22,328)
Income tax benefit	260	0
Net loss	$ (523)	$ (22,328)
Income (loss) per common share
Basic	$ (0.05)	$ (2.09)
Diluted	$ (0.05)	$ (2.09)
Weighted average number of common shares outstanding:
Basic	10,935,787	10,689,615
Diluted	10,935,787	10,689,615

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Treasury Stock	Total
Beginning Balance, shares at Dec. 31, 2016	10,624,714			(150,000)
Beginning Balance, amount at Dec. 31, 2016	$ 106	$ 36,819	$ (19,422)	$ (800)	$ 16,703
Common stock issued for services, shares	300,799			150,000
Common stock issued for services, amount	$ 3	88		$ 800	891
Net loss			(22,328)		(22,328)
Ending Balance, shares at Dec. 31, 2017	10,925,513			0
Ending Balance, amount at Dec. 31, 2017	$ 109	36,907	(41,750)	$ 0	(4,734)
Common stock issued for services, shares	50,001
Common stock issued for services, amount	$ 1	29			30
Net loss			(523)		(523)
Ending Balance, shares at Dec. 31, 2018	10,975,514			0
Ending Balance, amount at Dec. 31, 2018	$ 110	$ 36,936	$ (42,273)	$ 0	$ (5,227)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
OPERATING ACTIVITIES
Net income (loss)	$ (523)	$ (22,328)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,933	1,810
Deferred income tax	(216)	0
Amortization of debt issue costs	128	128
Accretion expense	266	287
Common stock issued for services	30	60
Recovery of bad debt	0	81
Impairment of fixed assets	0	303
Changes in operating assets and liabilities
Accounts receivable	978	584
Accounts receivable, related party	653	509
Prepaid expenses and other current assets	(579)	(161)
Deposits and other assets	(65)	(15)
Inventory	1,579	(1,014)
Accrued arbitration award	(6,000)	27,128
Accounts payable, accrued expenses and other liabilities	2,266	(12,921)
Accounts payable, related party	555	605
Net cash provided by (used in) operating activities	1,005	(4,944)
INVESTING ACTIVITIES
Capital expenditures	(2,029)	(2,432)
Net cash used in investing activities	(2,029)	(2,432)
FINANCING ACTIVITIES
Proceeds from issuance of debt	0	3,678
Payments on debt	(890)	(1,364)
Net activity on related-party debt	1,433	1,125
Net cash provided by (used in) financing activities	543	3,439
Net change in cash, cash equivalents, and restricted cash	(481)	(3,937)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	2,146	6,083
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	1,665	2,146
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	4	1,651
Financing of guaranty fees via long-term debt, related party	644	327
Conversion of related-party notes to common stock	0	831
Interest paid	2,823	2,688
Income taxes paid	$ 0	$ 0

1. Organization

1. Organization	12 Months Ended
	Dec. 31, 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 Annual Report for further information related to the NPS assignment. See “Part I, Item 1. Business” and “Part I, Item 2. Properties” in this Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets. Going Concern ● Consecutive Net Losses and Working Capital Deficits At December 31, 2018, we had a working capital deficit of $71.9 million. Excluding the current portion of long-term debt, we had a working capital deficit of $30.0 million at December 31, 2018. At December 31, 2017, we had a working capital deficit of $69.5 million. Excluding the current portion of long-term debt, we had a working capital deficit of $30.0 million at December 31, 2017. ● Final Arbitration Award and Settlement Agreement 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. LE, NPS, and Blue Dolphin, together with LEH, Carroll & Company Financial Holdings, L.P. (“C&C”), and Jonathan Carroll (collectively referred to herein as the “Lazarus Parties”), entered into that certain Settlement Agreement with GEL, dated as of July 20, 2018 (as may be further amended, restated, supplemented or otherwise modified from time to time, the “Settlement Agreement”), whereby GEL and the Lazarus Parties agreed to mutually release all claims against each other and to file a stipulation of dismissal with prejudice in connection with the GEL Arbitration (the “Settlement”), subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon payment by the Lazarus Parties to GEL of $10.0 million in cash (the “Settlement Payment”). Until either the Settlement Payment is made or the Settlement Agreement is terminated, the Lazarus Parties must pay GEL $0.5 million in cash at the end of each calendar month (the “Interim Payments”). 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 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. At December 31, 2018 and 2017, accrued arbitration award payable on our consolidated balance sheet was $21.1 million and $27.1 million, respectively. 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. Unless extended in writing by GEL, the Settlement Agreement will terminate on July 31, 2019 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 GEL 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. On February 1, 2019, GEL filed a proposed order granting a joint motion to continue the District Court Action. ● Defaults Under Veritex Secured Loan Agreements – Events of Default Veritex has not accelerated or called due the secured loan agreements considering the Settlement Agreement, which Veritex must ultimately approve. Instead, Veritex has 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. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets at December 31, 2018 and 2017 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future. Veritex has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the Settlement. We 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. Further, we can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement, Veritex may exercise its rights and remedies under the secured loan agreements. In either 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, (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws, and (iii) the trading prices of our common stock and the value of an investment in our common stock could significantly decrease, which could lead to holders of our common stock losing their investment in our common stock in its entirety. – Financial Covenant Defaults Veritex has been working with LE and LRM and continues to be aware and party to all discussions and arrangements with GEL surrounding the executed settlement agreement and all amendments and extensions with GEL. 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. Operating Risks For additional disclosures related to the Final Arbitration Award, the Settlement Agreement, defaults under secured loan agreements, our business strategy, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Annual Report: ● Part I, Item 1. Business – Business Strategy ● Part I, Item 1A. Risk Factors ● Part I, Item 3. Legal Proceedings ● Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Final Arbitration Award and Settlement Agreement – Results of Operations – Liquidity and Capital Resources ● Part II, Item 8. Financial Statements and Supplementary Data: – Note (9) Related-Party Transactions – Note (11) Long-Term Debt, Net – Note (19) Commitments and Contingencies – Legal Matters

2. Basis of Presentation

2. Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in consolidation. The accompanying consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for consolidated financial information pursuant to the rules and regulations of the SEC under Regulation S-X and the instructions to Form 10-K. 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.

3. Significant Accounting Polic

3. Significant Accounting Policies	12 Months Ended
	Dec. 31, 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 Accounts Receivable and Allowance for Doubtful Accounts 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 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented. 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 We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between sale and when payment is due is not significant. Transportation, shipping, and handling costs incurred are included in cost of goods sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. Tolling and Terminaling Revenue We typically satisfy performance obligations for tolling and terminaling operations with the passage of time. We determine the transaction price at agreement inception based on the guaranteed minimum amount of revenue over the term of the agreement. We allocate the transaction price to the single performance obligation that exists under the agreement, and we recognize revenue in the amount for which we have a right to invoice. Generally, payment terms do not exceed 30 days. Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period. Income Taxes We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current reporting period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of December 31, 2018 and 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”) credit carryforwards. In addition, we have NOL carryforwards that remain available for future use. The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At December 31, 2018 and 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (17) 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 (18) Earnings Per Share” for additional information related to EPS.) New Pronouncements Adopted ASU 2018-09, Codification Improvements ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Collaborative Arrangements (Topic 808) New Pronouncements Issued, Not Yet Effective ASUs 2018-20, 2018-11, 2018-10, and 2016-02, Leases (Topic 842) For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-20, 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in an increase of approximately $1.0 million in our total assets and liabilities on our consolidated balance sheets. We do not expect adoption of this guidance to have a significant impact on our consolidated statements of operations. ASU 2018-17, Consolidation (Topic 810) arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. For entities other than private companies, the amendments in ASU 2018-17 are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements. ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Revenue and Segment Informat

4. Revenue and Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Revenue and Segment Information	We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility. Revenue from Contracts with Customers ● Disaggregation of Revenue ● Receivables from Contracts with Customers ● Remaining Performance Obligations Segment Information Twelve Months December 31, 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) $ 337,038 $ 3,723 $ — $ 340,761 $ 258,449 $ — $ 258,449 Intercompany fees and sales (3,270 ) 3,270 — — — — — Operation costs and expenses(1) (331,220 ) (1,332 ) (444 ) (332,996 ) (273,671 ) (817 ) (274,488 ) Segment contribution margin $ 2,548 $ 5,661 $ (444 ) $ 7,765 $ (15,222 ) $ (817 ) $ (16,039 ) General and administrative expenses (1,232 ) (245 ) (1,795 ) (3,272 ) (2,850 ) (1,172 ) (4,022 ) Depreciation and amortization (1,842 ) (91 ) — (1,933 ) (1,799 ) (10 ) (1,810 ) Interest and other non-operating expenses, net(2) (3,343 ) (457 ) Loss before income taxes (783 ) (22,328 ) Income tax benefit 260 — Net loss $ (523 ) $ (22,328 ) Capital expenditures $ 1,124 $ 905 $ — $ 2,029 $ 4,082 $ — $ 4,082 Identifiable assets $ 41,116 $ 28,446 $ 1,115 $ 70,677 $ 71,708 $ 1,700 $ 73,408 Business segment information for the periods indicated (and as of the dates indicated) was as follows: (1) Operation costs within Refinery Operations includes the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes terminal operating expenses, an allocation of other costs (e.g. insurance and maintenance), and associated refinery fuel use costs. Operation cost within Corporate and Other includes expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Reflects FLNG Land II, Inc. easement revenue in 2017. See “Note (19) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG.

5. NPS Assignment

5. NPS Assignment	12 Months Ended
	Dec. 31, 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 twelve months ended December 31, 2018. NPS did not have significant assets, liabilities or results of operations for the twelve months ended December 31, 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	12 Months Ended
	Dec. 31, 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: December 31, 2018 2017 Prepaid crude oil and condensate $ 1,166 $ 913 Prepaid insurance 437 294 Other prepaids 183 — $ 1,786 $ 1,207

7. Inventory

7. Inventory	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: December 31, 2018 2017 (in thousands) Crude oil and condensate $ 861 $ 961 AGO 276 213 Naphtha 143 170 Chemicals 106 162 HOBM 102 1,558 Propane 17 17 LPG mix 5 8 $ 1,510 $ 3,089

8. Property, Plant and Equipmen

8. Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 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: December 31, 2018 2017 (in thousands) Refinery and facilities $ 63,058 $ 51,432 Land 566 566 Other property and equipment 747 653 64,371 52,651 Less: Accumulated depletion, depreciation, and amortization (10,429 ) (8,495 ) 53,942 44,156 Construction in progress 10,755 20,441 $ 64,697 $ 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 $1.3 million and $3.9 million at December 31, 2018 and 2017, respectively. Capital expenditures at the Nixon Facility are being funded by working capital derived from revenue from operations and LEH and its affiliates (including Jonathan Carroll), as well as from long-term debt from Veritex that was secured in 2015 for expansion of the Nixon Facility. Unused amounts under the Veritex loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets and will be available for use once events of default associated with the Final Arbitration Award are remedied. See “Note (11) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

9. Related Party Transactions

9. Related Party Transactions	12 Months Ended
	Dec. 31, 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 Office Sub-Lease Agreement Financial Agreements . We currently rely on LEH and its affiliates (including Jonathan Carroll) to fund our working capital requirements. During 2018 and 2017, LEH and its affiliates (Ingleside and Jonathan Carroll) provided working capital to Blue Dolphin in the form of a term loan and non-cash advances (such as conversion of accounts payable to debt under promissory notes). Our long-term debt, related party is currently in default. There can be no assurance that LEH and its affiliates will continue to fund our working capital requirements. Outstanding principal and accrued interest owed under these financial agreements are reflected in long-term debt, related party, current portion in our consolidated balance sheets. BDPL Loan Agreement ( ) Principal Amount: $4.0 million Maturity Date: August 2018 Principal and Interest Payment: $500,000 annually Interest Rate: 16.00% The proceeds of the BDPL Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the BDPL Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the BDPL Loan Agreement is reflected in interest payable, related party, current portion in our consolidated balance sheets. Promissory Notes ( ) ● June LEH Note ● March Ingleside Note ● March Carroll Note Amended and Restated Guaranty Fee Agreements Debt Assumption Agreement Financial Statements Impact Consolidated Balance Sheets Long-term debt, related party associated with the BDPL Loan Agreement, the March Ingleside Note, and the March Carroll Note as of the dates indicated was as follows: December 31, 2018 2017 (in thousands) LEH $ 4,611 $ 4,000 Ingleside 1,283 1,169 Jonathan Carroll 1,147 439 7,041 5,608 Less: Long-term debt, related party, current portion (7,041 ) (4,000 ) $ — $ 1,608 Accrued interest associated with the BDPL Loan Agreement was $1.5 million and $0.9 million at December 31, 2018 and 2017, respectively. Interest on the March Ingleside Note and the March Carroll Note is compounded and reported as part of the outstanding balance. Consolidated Statements of Operations Twelve Months Ended December 31, 2018 2017 (in thousands, except percent amounts) Refinery operations LEH $ 98,571 28.9 % $ 81,094 31.3 % Other customers 238,467 70.0 % 174,453 67.5 % Tolling and terminaling LEH — 0.0 % 675 0.3 % Other customers 3,723 1.1 % 2,227 0.9 % $ 340,761 100.0 % $ 258,449 100.0 % Fees associated with the Dock Tolling Agreement with LMT totaled $0.6 million for both the twelve months ended December 31, 2018 and 2017. Lease payments under the office sub-lease agreement with LEH totaled $0.03 million and $0.2 million for the twelve months ended December 31, 2018 and 2017, respectively. The LEH operating fee for the twelve months ended December 31, 2018 totaled $0.6 million compared to $0.8 million, a decrease of $0.2 million, or 25%, compared to the same twelve-month period a year earlier. The decrease in the LEH operating fee was due to the fee restructure under the Amended and Restated Operating Agreement in April 2017. Interest expense associated with the BDPL Loan Agreement, the Amended and Restated Guaranty Fee Agreements, and the related-party promissory notes (the June LEH Note, the March Ingleside Note, and the March Carroll Note) for the periods indicated was as follows: Twelve Months Ended December 31, 2018 2017 Jonathan Carroll $ 700 $ 685 LEH 648 706 Ingleside 97 92 $ 1,445 $ 1,483

10. Accrued Expenses and Other

10. Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities as of the dates indicated consisted of the following: December 31, 2018 2017 (in thousands) Unearned revenue $ 434 $ 450 Board of director fees payable 273 207 Other payable 265 116 Easement payable 223 — Accrued rent 111 — Customer deposits 109 109 Insurance 61 68 Property taxes 48 131 Excise and income taxes payable 47 79 $ 1,571 $ 1,160

11. Long-Term Debt, Net

11. Long-Term Debt, Net	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt, Net	USDA Guaranteed Loans Amended and Restated Guaranty Fee Agreements epayment Twelve Months Ended December 31, 2018 2017 First Term Loan Due 2034 $ 456 $ 471 Second Term Loan Due 2034 188 192 $ 644 $ 663 Defaults in USDA-Guaranteed Loan Agreements Long-Term Debt, Net Outstanding Balances December 31, 2018 2017 First Term Loan Due 2034 (in default) $ 22,550 $ 23,199 Second Term Loan Due 2034 (in default) 9,300 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 41 — $ 36,869 $ 37,679 Less: Current portion of long-term debt, net (34,863 ) (35,544 ) Less: Unamortized debt issue costs (2,006 ) (2,135 ) $ — $ — Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following: 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 (436 ) (307 ) $ 2,006 $ 2,135 Amortization expense was $0.1 million for both the twelve months ended December 31, 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: December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,843 $ 2,046 BDPL Loan Agreement (related party, in default) 1,534 892 Second Term Loan Due 2034 (in default) 53 49 First Term Loan Due 2034 (in default) 43 40 4,473 3,027 Less: Interest payable, current portion (4,473 ) (3,027 ) Long-term interest payable, net of current portion $ — $ — At December 31, 2018, our expected future debt payments are presented as current due to defaults under the loan agreements: Years Ending December 31, Principal Debt Issue Costs Total 2019 $ 43,910 $ (2,006 ) $ 41,904 2020 - - - 2021 - - - 2022 - - - 2023 - - - Subsequent to 2023 - - - $ 43,910 $ (2,006 ) $ 41,904 First Term Loan Due 2034 (In Default) Principal Amount: $25.0 million Maturity Date: June 2034 Principal and Interest Payment: $0.2 million monthly Interest Rate: Wall Street Journal Prime Rate plus 2.75% A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034, which is 100% USDA-guaranteed, is secured by: (i) a first lien on the Nixon Facility’s business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a payment reserve account held by Veritex, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets. Second Term Loan Due 2034 (In Default) Principal Amount: $10.0 million Maturity Date: December 2034 Principal and Interest Payment: $0.1 million monthly Interest Rate: Wall Street Journal Prime Rate plus 2.75% A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million, the funds of which were used to purchase idle refinery equipment for refurbishment and use at the Nixon Facility. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034, which is 100% USDA-guaranteed, is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under a term loan that matured in 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Veritex makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash (current portion) and restricted cash, noncurrent in our consolidated balance sheets. Notre Dame Debt (In Default) Original Principal Amount: $8.0 million Additional Principal: $3.7 million Maturity Date: January 2018 Principal and Interest Payment: None; payment rights subordinated to senior lender Default Interest Rate: 16.00% Pursuant to a Sixth Amendment to the Notre Dame Debt, entered on November 14, 2017 and made effective September 18, 2017, the Notre Dame Debt was amended to increase the principal amount by $3.7 million (the “Additional Principal”). The Additional Principal was used to make payments to GEL to reduce the balance of the Final Arbitration Award in the amount of $3.6 million in accordance with the GEL Letter Agreement. Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate its right to payments, as well as any security interest and liens on the Nixon Facility’s business assets, in favor of Veritex as holder of the First Term Loan Due 2034. To date, no payments have been made to Notre Dame Investors, Inc. under the Notre Dame Debt. The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Capital Leases ● Boiler Equipment Lease ● Crane Lease A summary of equipment held under long-term capital leases as of the dates indicated follows: December 31, 2018 2017 (in thousands) Boiler equipment $ — $ 539 Crane 94 — Less: accumulated depreciation (14 ) (21 ) $ 80 $ 518 Years Ending December 31, Total 2019 $ 41 2020 - 2021 - 2022 - 2023 - Subsequent to 2023 - $ 41

12. Asset Retirement Obligation

12. Asset Retirement Obligations	12 Months Ended
	Dec. 31, 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: December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 265 287 2,580 2,315 Less: asset retirement obligations, current portion (2,580 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ — $ — BDPL’s Blue Dolphin Pipeline has been inactive since September 2012. Due to the length of inactivity, BDPL is required by the Bureau of Safety and Environmental Enforcement (“BSEE”) to: (i) flush and fill the Blue Dolphin Pipeline, (ii) abandon-in-place a portion of the Blue Dolphin Pipeline’s 20” segment and certain smaller diameter connecting lateral lines that reside offshore in federal waters and (iii) remove from federal waters the GA-288C anchor platform. In April 2016, BDPL submitted decommissioning permit applications to BSEE for three (3) pipeline segments – Segments #13101, #9428, and #15635 – and the GA-288C anchor platform. In June 2016, BDPL also submitted a decommissioning permit application to the U.S. Army Corps of Engineers for abandonment of Segment #9428. The permit applications were granted by BSEE at varying dates between August 2016 and April 2017. Work must typically be completed within 120 days from the date of permit approval. Abandonment timing primarily depends on resource availability and weather conditions in the Gulf of Mexico. Management anticipates performing abandonment work during 2019. Weather conditions in the Gulf of Mexico during the winter months is typically not conducive to abandonment operations. As of the date of this Annual Report, decommissioning work has not yet been completed.

13. Impairment

13. Impairment	12 Months Ended
	Dec. 31, 2018
Impairment
Impairment	For the years ended December 31, 2018 and 2017, we recorded impairment expense of $0 and $0.3 million, respectively. The impairment expense for the year ended December 31, 2017 related to trade name. At the time of the 2012 reverse acquisition, our trade name valuation was tied to pipeline transportation and exploration and production revenue and assumed, under the relief-from-royalty approach, a growth rate of 2.2% annually. Although growth in these operations did not materialize for economic reasons, management believed there was value associated with Blue Dolphin’s listing as a publicly-traded company. Given the decline in the price per share of our common stock following the Final Arbitration Award, we fully impaired the trade name asset. Trade name is not associated with, nor is it material to, our refinery operations business segment.

14. Treasury Stock

14. Treasury Stock	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Treasury Stock	At December 31, 2018 and 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. (See “Note (9) Related-Party Transactions” and “Note (11) Long-Term Debt, Net – Amended and Restated Guaranty Fee Agreements” for additional disclosures related to Jonathan Carroll and the Amended and Restated Guaranty Fee Agreements.)

15. Concentration of Risk

15. Concentration of Risk	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier Operation of the Nixon refinery depends on our ability to purchase adequate amounts of crude oil and condensate, which is primarily dependent on our liquidity and access to capital. We 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 twelve months ended December 31, 2018, we had 4 customers that accounted for approximately 91% 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 December 31, 2018, these 4 customers represented approximately $0.1 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 (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.) For the twelve months ended December 31, 2017, we had 3 customers that accounted for approximately 70% of our refined petroleum product sales. LEH was 1 of these 3 significant customers and accounted for approximately 33% of our refined petroleum product sales. At December 31, 2017, these 3 customers represented approximately $1.3 million in accounts receivable. LEH represented approximately $0.7 in accounts receivable. Refined Petroleum Product Sales Twelve Months Ended December 31, 2018 2017 (in thousands) LPG mix $ 3 0.0 % $ 123 0.0 % Naphtha 82,982 24.6 % 60,408 23.6 % Jet fuel 98,570 29.2 % 81,094 31.7 % HOBM 80,979 24.1 % 54,851 21.5 % AGO 74,504 22.1 % 59,071 23.2 % $ 337,038 100.0 % $ 255,547 100.0 %

16. Leases

16. Leases	12 Months Ended
	Dec. 31, 2018
Accounting Policies [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 7,675 square feet is approximately $0.02 million per month. LEH subleases approximately 82% of this leased office space [see “Note (9) Related-Party Transactions” related to the LEH office sub-lease agreement]. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For the twelve months ended December 31, 2018 and 2017, rent expense totaled $0.2 million. At December 31, 2018, future minimum lease commitments that are non-cancelable under the Lease Amendment are as follow: Years Ending December 31, 2019 $ 190 2020 230 2021 233 2022 237 2023 161 $ 1,051

17. Income Taxes

17. Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	The Tax Cuts and Jobs Act was signed into law in December 2017. 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 twelve months ended December 31, 2018 and 2017. The provision for income tax benefit (expense) as of the dates indicated consisted of the following: 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 $ — 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 twelve months ended December 31, 2018 and 2017, we recognized income relating to state income tax of $0.04 million and $0, respectively. Effective Tax Rate December 31, 2018 2017 Expected tax rate (21.00 %) (34.00 %) Permanent differences 0.00 % 0.00 % State tax (5.10 %) 0.00 % Federal tax (28.10 %) 0.00 % Change in valuation allowance 21.00 % 34.00 % (33.2 %) 0.00 % In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to AMT credits made refundable by the Tax Cuts and Jobs Act. 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, resulting in there being no impact on our net deferred tax assets. Deferred income taxes as of the dates indicated consisted of the following: December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 11,260 $ 9,767 Accrued arbitration award payable 2,850 4,122 Business interest expense 704 — Start-up costs (crude oil and condensate processing facility) 678 763 Asset retirement obligations liability/deferred revenue 542 495 AMT credit and other 108 217 Total deferred tax assets 16,142 15,365 Deferred tax liabilities: Basis differences in property and equipment (5,153 ) (4,415 ) Total deferred tax liabilities (5,153 ) (4,415 ) 10,989 10,950 Valuation allowance (10,881 ) (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 $ 23,563 $ 33,177 Net operating losses — 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,219 $ 39,833 Net operating losses — 7,106 7,106 Balance at December 31, 2018 $ 9,614 $ 37,325 $ 46,939 Valuation Allowance

18. Earnings Per Share

18. Earnings Per Share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Twelve Months Ended December 31, 2018 2017 Net loss $ (523 ) $ (22,328 ) Basic and diluted loss per share $ (0.05 ) $ (2.09 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,935,787 10,689,615 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 twelve months ended December 31, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

19. Commitments and Contingenci

19. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Matters Final Arbitration Award and Settlement Agreement Veritex Secured Loan Agreement Events 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 Separate Orders, the settlement 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 December 31, 2018. As of December 31, 2018 and 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)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable, Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
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 2018. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2018. We did not record any impairment of our refinery and facilities assets for the periods presented. 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 We consider a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the refined petroleum product, the transfer of significant risks and rewards, our rights to payment, and transfer of legal title. In each case, the term between sale and when payment is due is not significant. Transportation, shipping, and handling costs incurred are included in cost of goods sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. Tolling and Terminaling Revenue We typically satisfy performance obligations for tolling and terminaling operations with the passage of time. We determine the transaction price at agreement inception based on the guaranteed minimum amount of revenue over the term of the agreement. We allocate the transaction price to the single performance obligation that exists under the agreement, and we recognize revenue in the amount for which we have a right to invoice. Generally, payment terms do not exceed 30 days. Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period.
Income Taxes	Income Taxes We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current reporting period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was cumulative losses incurred over the three-year period ended December 31, 2018. Such objective evidence limits the ability to consider other subjective evidence, such as projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of December 31, 2018 and 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”) credit carryforwards. In addition, we have NOL carryforwards that remain available for future use. The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At December 31, 2018 and 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (17) 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 (18) Earnings Per Share” for additional information related to EPS.)
New Pronouncements Adopted	New Pronouncements Adopted ASU 2018-09, Codification Improvements ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Collaborative Arrangements (Topic 808)
New Pronouncements Issued, Not Yet Effective	New Pronouncements Issued, Not Yet Effective ASUs 2018-20, 2018-11, 2018-10, and 2016-02, Leases (Topic 842) For a public business entity, the amendments in ASUs 2018-11 and 2018-10 affect the amendments in ASU 2016-02, which are not yet effective, but for which early adoption upon issuance is permitted. For entities that early adopted Topic 842, the amendments are effective upon issuance of ASUs 2018-20, 2018-11 and 2018-10, and the transition requirements are the same as those in Topic 842. For entities that have not adopted Topic 842, the effective date and transition requirements will be the same as the effective date and transition requirements in Topic 842. Adoption of this guidance affects leases with a term of greater than 12-months and will result in an increase of approximately $1.0 million in our total assets and liabilities on our consolidated balance sheets. We do not expect adoption of this guidance to have a significant impact on our consolidated statements of operations. ASU 2018-17, Consolidation (Topic 810) arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. For entities other than private companies, the amendments in ASU 2018-17 are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. We do not expect adoption of this guidance to have a significant impact on our consolidated financial statements. ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Revenue and Segment Inform_2

4. Revenue and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Business segment reporting	Twelve Months December 31, 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) $ 337,038 $ 3,723 $ — $ 340,761 $ 258,449 $ — $ 258,449 Intercompany fees and sales (3,270 ) 3,270 — — — — — Operation costs and expenses(1) (331,220 ) (1,332 ) (444 ) (332,996 ) (273,671 ) (817 ) (274,488 ) Segment contribution margin $ 2,548 $ 5,661 $ (444 ) $ 7,765 $ (15,222 ) $ (817 ) $ (16,039 ) General and administrative expenses (1,232 ) (245 ) (1,795 ) (3,272 ) (2,850 ) (1,172 ) (4,022 ) Depreciation and amortization (1,842 ) (91 ) — (1,933 ) (1,799 ) (10 ) (1,810 ) Interest and other non-operating expenses, net(2) (3,343 ) (457 ) Loss before income taxes (783 ) (22,328 ) Income tax benefit 260 — Net loss $ (523 ) $ (22,328 ) Capital expenditures $ 1,124 $ 905 $ — $ 2,029 $ 4,082 $ — $ 4,082 Identifiable assets $ 41,116 $ 28,446 $ 1,115 $ 70,677 $ 71,708 $ 1,700 $ 73,408

6. Prepaid Expenses and Other_2

6. Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Liabilities extinguished
Prepaid expenses and other current assets	December 31, 2018 2017 Prepaid crude oil and condensate $ 1,166 $ 913 Prepaid insurance 437 294 Other prepaids 183 — $ 1,786 $ 1,207

7. Inventory (Tables)

7. Inventory (Tables)	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Inventory	December 31, 2018 2017 (in thousands) Crude oil and condensate $ 861 $ 961 AGO 276 213 Naphtha 143 170 Chemicals 106 162 HOBM 102 1,558 Propane 17 17 LPG mix 5 8 $ 1,510 $ 3,089

8. Property, Plant and Equipm_2

8. Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property and equipment	December 31, 2018 2017 (in thousands) Refinery and facilities $ 63,058 $ 51,432 Land 566 566 Other property and equipment 747 653 64,371 52,651 Less: Accumulated depletion, depreciation, and amortization (10,429 ) (8,495 ) 53,942 44,156 Construction in progress 10,755 20,441 $ 64,697 $ 64,597

9. Related Party Transactions (

9. Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Accounts Payable, Related Party	December 31, 2018 2017 (in thousands) LEH $ 4,611 $ 4,000 Ingleside 1,283 1,169 Jonathan Carroll 1,147 439 7,041 5,608 Less: Long-term debt, related party, current portion (7,041 ) (4,000 ) $ — $ 1,608
Refinery operating expenses	Twelve Months Ended December 31, 2018 2017 (in thousands, except percent amounts) Refinery operations LEH $ 98,571 28.9 % $ 81,094 31.3 % Other customers 238,467 70.0 % 174,453 67.5 % Tolling and terminaling LEH — 0.0 % 675 0.3 % Other customers 3,723 1.1 % 2,227 0.9 % $ 340,761 100.0 % $ 258,449 100.0 %
Accrued interest Expenses	Twelve Months Ended December 31, 2018 2017 (in thousands) Jonathan Carroll $ 700 $ 685 LEH 648 706 Ingleside 97 92 $ 1,445 $ 1,483

10. Accrued Expenses and Othe_2

10. Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Expenses And Other Current Liabilities
Accrued expenses and other current liabilities	December 31, 2018 2017 (in thousands) Unearned revenue $ 434 $ 450 Board of director fees payable 273 207 Other payable 265 116 Easement payable 223 — Accrued rent 111 — Customer deposits 109 109 Insurance 61 68 Property taxes 48 131 Excise and income taxes payable 47 79 $ 1,571 $ 1,160

11. Long-Term Debt, Net (Tables

11. Long-Term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Guaranty fees	Twelve Months Ended December 31, 2018 2017 (in thousands) First Term Loan Due 2034 $ 456 $ 471 Second Term Loan Due 2034 188 192 $ 644 $ 663
Long Term Debt	December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 22,550 $ 23,199 Second Term Loan Due 2034 (in default) 9,300 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 41 - $ 36,869 $ 37,679 Less: Current portion of long-term debt, net (34,863 ) (35,544 ) Less: Unamortized debt issue costs (2,006 ) (2,135 ) $ - $ -
Debt issue costs	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 (436 ) (307 ) $ 2,006 $ 2,135
Accrued interest related to our long-term debt, net	December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,843 $ 2,046 BDPL Loan Agreement (related party, in default) 1,534 892 Second Term Loan Due 2034 (in default) 53 49 First Term Loan Due 2034 (in default) 43 40 4,473 3,027 Less: Interest payable, current portion (4,473 ) (3,027 ) Long-term interest payable, net of current portion $ - $ -
Schedule of summary of equipment held under long-term capital leases	Years Ending December 31, Principal Debt Issue Costs Total 2019 $ 43,910 $ (2,006 ) $ 41,904 2020 - - - 2021 - - - 2022 - - - 2023 - - - Subsequent to 2023 - - - $ 43,910 $ (2,006 ) $ 41,904
Summary of equipment held under long-term capital leases	December 31, 2018 2017 (in thousands) Boiler equipment $ - $ 539 Crane 94 - Less: accumulated depreciation (14 ) (21 ) $ 80 $ 518 Years Ending December 31, Total 2019 $ 41 2020 - 2021 - 2022 - 2023 - Subsequent to 2023 - $ 41

12. Asset Retirement Obligati_2

12. Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 265 287 2,580 2,315 Less: asset retirement obligations, current portion (2,580 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ — $ —

15. Concentration of Risk (Tabl

15. Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2018
Concentration Of Risk
Percentages of all refined petroleum products sales to total sales	Twelve Months Ended December 31, 2018 2017 (in thousands) LPG mix $ 3 0.0 % $ 123 0.0 % Naphtha 82,982 24.6 % 60,408 23.6 % Jet fuel 98,570 29.2 % 81,094 31.7 % HOBM 80,979 24.1 % 54,851 21.5 % AGO 74,504 22.1 % 59,071 23.2 % $ 337,038 100.0 % $ 255,547 100.0 %

16. Leases (Tables)

16. Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Future minimum lease payments	Years Ending December 31, 2019 $ 190 2020 230 2021 233 2022 237 2023 161 $ 1,051

17. Income Taxes (Tables)

17. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	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 $ —
Effective tax rate	December 31, 2018 2017 Expected tax rate (21.00 %) (34.00 %) Permanent differences 0.00 % 0.00 % State tax (5.10 %) 0.00 % Federal tax (28.10 %) 0.00 % Change in valuation allowance 21.00 % 34.00 % (33.2 %) 0.00 %
Deferred tax assets and deferred tax liabilities	December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 11,260 $ 9,767 Accrued arbitration award payable 2,850 4,122 Business interest expense 704 — Start-up costs (crude oil and condensate processing facility) 678 763 Asset retirement obligations liability/deferred revenue 542 495 AMT credit and other 108 217 Total deferred tax assets 16,142 15,365 Deferred tax liabilities: Basis differences in property and equipment (5,153 ) (4,415 ) Total deferred tax liabilities (5,153 ) (4,415 ) 10,989 10,950 Valuation allowance (10,881 ) (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 $ 23,563 $ 33,177 Net operating losses — 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,219 $ 39,833 Net operating losses — 7,106 7,106 Balance at December 31, 2018 $ 9,614 $ 37,325 $ 46,939

18. Earnings Per Share (Tables)

18. Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings per share	Twelve Months Ended December 31, 2018 2017 Net loss $ (523 ) $ (22,328 ) Basic and diluted loss per share $ (0.05 ) $ (2.09 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,935,787 10,689,615

3. Significant Accounting Pol_3

3. Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 14	$ 495
Restricted cash	49	49
Restricted cash, noncurrent	1,602	1,602
Allowance for doubtful accounts	100,000	0
Impairment expense	$ 0	$ 303

4. Business Segment Information

4. Business Segment Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Net revenues (excluding intercompany fees and sales)	$ 340,761	$ 258,449
Intercompany fees and sales	0	0
Operation costs and expenses(1)	(332,996)	(274,488)
Segment contribution margin	7,765	(16,039)
General and administrative expenses	(3,272)	(4,022)
Depreciation and amortization	(1,933)	(1,810)
Interest and other non-operating expenses, net(2)	(3,343)	(457)
Loss before income taxes	(783)	(22,328)
Income tax benefit	260	0
Net loss	(523)	(22,328)
Capital expenditures	2,029	4,082
Identifiable assets	70,677	73,408
Segment Refinery Operations [Member]
Net revenues (excluding intercompany fees and sales)	337,038	258,449
Intercompany fees and sales	(3,270)	0
Operation costs and expenses(1)	(331,220)	(273,671)
Segment contribution margin	2,548	(15,222)
General and administrative expenses	(1,232)	(2,850)
Depreciation and amortization	(1,842)	(1,799)
Capital expenditures	1,124	4,082
Identifiable assets	41,116	71,708
Tolling and Terminaling [Member]
Net revenues (excluding intercompany fees and sales)	3,723
Intercompany fees and sales	3,270
Operation costs and expenses(1)	(1,332)
Segment contribution margin	5,661
General and administrative expenses	(245)
Depreciation and amortization	(91)
Capital expenditures	905
Identifiable assets	28,446
Corporate and Other
Net revenues (excluding intercompany fees and sales)	0	0
Intercompany fees and sales	0	0
Operation costs and expenses(1)	(444)	(817)
Segment contribution margin	(444)	(817)
General and administrative expenses	(1,795)	(1,172)
Depreciation and amortization	0	(10)
Capital expenditures	0	0
Identifiable assets	$ 1,115	$ 1,700

6. Prepaid Expenses and Other_3

6. Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Long-Term Debt Details 1
Prepaid crude oil and condensate	$ 1,165	$ 913
Prepaid insurance	437	294
Other prepaids	183	0
Prepaid Expenses, Net	$ 1,786	$ 1,207

7. Inventory (Details)

7. Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and condensate	$ 861	$ 961
AGO	276	213
Naphtha	143	170
Chemicals	106	162
HOBM	102	1,558
Propane	17	17
LPG mix	5	8
Inventories, Net	$ 1,510	$ 3,089

8. Property, Plant and Equipm_3

8. Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accretion from discontinued operations
Refinery and facilities	$ 63,058	$ 51,432
Land	566	566
Other property and equipment	747	653
Property, Plant and Equipment, Gross	64,371	52,651
Less: Accumulated depletion, depreciation, and amortization	(10,429)	(8,495)
Property, Plant and Equipment less depreciation	53,942	44,156
Construction in Progress	10,755	20,441
Property, Plant and Equipment, Net	$ 64,697	$ 64,597

8. Property, Plant and Equipm_4

8. Property, Plant and Equipment, Net (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property Plant And Equipment Net
Interest Costs Capitalized	$ 1,300	$ 3,900

9. Related Party Transactions_2

9. Related Party Transactions (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 30, 2017
Prepaid operating expenses, related party	$ 7,041	$ 5,608
Less: Long-term debt - current portion, related party	(34,863)	(35,544)
Long-term debt - net of current portion, related party	0	1,608
LEH [Member]
Prepaid operating expenses, related party	4,611		$ 4,100
Ingleside [Member]
Prepaid operating expenses, related party	1,283	1,169
Jonathan Carroll [Member]
Prepaid operating expenses, related party	$ 1,147	$ 439

9. Related Party Transactions_3

9. Related Party Transactions (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue	$ 340,761	$ 258,449
Concentration	100.00%	100.00%
Segment Refinery Operations [Member]
Revenue	$ 337,038	$ 258,449
Tolling and Terminaling [Member]
Revenue	3,723
LEH [Member] | Segment Refinery Operations [Member]
Revenue	$ 98,571	$ 81,094
Concentration	28.90%	31.30%
LEH [Member] | Tolling and Terminaling [Member]
Revenue	$ 0	$ 675
Concentration	0.00%	0.30%
Other Customers [Member] | Segment Refinery Operations [Member]
Revenue	$ 238,467	$ 174,453
Concentration	70.00%	67.50%
Other Customers [Member] | Tolling and Terminaling [Member]
Revenue	$ 3,723	$ 2,227
Concentration	1.10%	0.90%

9. Related Party Transactions_4

9. Related Party Transactions (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Interest expenses under loan and guarantee, related party	$ 1,445	$ 1,483
LEH [Member]
Interest expenses under loan and guarantee, related party	700	685
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	648	706
Ingleside [Member]
Interest expenses under loan and guarantee, related party	$ 97	$ 92

9. Related Party Transactions_5

9. Related Party Transactions (Details Narrative) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Related Party Transactions Details Abstract
Accounts receivable, related party	$ 0	$ 653

10. Accrued Expenses and Othe_3

10. Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accrued Expenses And Other Current Liabilities Details Abstract
Unearned revenue	$ 434	$ 450
Board of director fees payable	273	207
Other payable	265	116
Easement payable	223	0
Accrued rent	111	0
Customer deposits	109	109
Insurance	61	68
Property taxes	48	131
Excise and income taxes payable	47	79
Accrued Expenses and Other Current Liabilities, Net	$ 1,571	$ 1,160

11. Long-Term Debt, Net (Detail

11. Long-Term Debt, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Guaranty fees	$ 644	$ 663
Term Loan Due 2034 [Member]
Guaranty fees	456	471
Second Term Loan Due 2034 [Member]
Guaranty fees	$ 188	$ 192

11. Long-Term Debt, Net (Deta_2

11. Long-Term Debt, Net (Details 1) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 22,550	$ 23,199
Second Term Loan Due 2034	9,300	9,502
Notre Dame Debt	4,978	4,978
Capital Leases	41	0
Total	36,869	37,679
Less: current portion of long-term debt	(34,863)	(35,544)
Less: unamortized debt issue costs	(2,006)	(2,135)
Long term debt	$ 0	$ 0

11. Long-Term Debt, Net (Deta_3

11. Long-Term Debt, Net (Details 2) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Issue Costs	$ 2,006	$ 2,135
Less: Accumulated amortization	(436)	(307)
First Term Loan Due 2034 [Member]
Debt Issue Costs	1,674	1,674
Second Term Loan Due 2034 [Member]
Debt Issue Costs	$ 768	$ 768

11. Long-Term Debt, Net (Deta_4

11. Long-Term Debt, Net (Details 3) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Interest payable	$ 4,473	$ 3,027
Less: Interest payable, current portion	(2,939)	(2,135)
Interest payable, noncurrent	0	0
Notre Dame Debt [Member]
Interest payable	2,843	2,046
BDPL Loan Agreement [Member]
Interest payable	1,534	892
Second Term Loan Due 2034 [Member]
Interest payable	53	49
First Term Loan Due 2034 [Member]
Interest payable	$ 43	$ 40

11. Long-Term Debt, Net (Deta_5

11. Long-Term Debt, Net (Details 4) $ in Thousands	Dec. 31, 2018USD ($)
2019	$ 41,904
2020	0
2021	0
2022	0
2023	0
Subsequent to 2023	0
Long Term Debt Payment, Net	41,904
Principal
2019	43,910
2020	0
2021	0
2022	0
2023	0
Subsequent to 2023	0
Long Term Debt Payment, Net	43,910
Debt Issuance Costs
2019	(2,006)
2020	0
2021	0
2022	0
2023	0
Subsequent to 2023	0
Long Term Debt Payment, Net	$ (2,006)

11. Long-Term Debt, Net (Deta_6

11. Long-Term Debt, Net (Details 5) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Less: accumulated depreciation	$ (14)	$ (21)
Capital lease obligation	80	518
Boiler equipment
Capital lease obligation	0	539
Crane
Capital lease obligation	$ 94	$ 0

11. Long-Term Debt, Net (Deta_7

11. Long-Term Debt, Net (Details 6) $ in Thousands	Dec. 31, 2018USD ($)
Long-term Debt Net
2019	$ 41
2020	0
2021	0
2022	0
2023	0
Subsequent to 2023	0
Total	$ 41

11. Long-Term Debt, Net (Deta_8

11. Long-Term Debt, Net (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Amortization expense	$ 128	$ 128
Principal balance outstanding	0	0
Guaranty fees	644	663
Capital Leases	41	0
Term Loan Due 2034 [Member]
Guaranty fees	456	471
Second Term Loan Due 2034 [Member]
Guaranty fees	$ 188	$ 192

12. Asset Retirement Obligati_3

12. Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations Details Abstract
Asset retirement obligations, at the beginning of the period	$ 2,315	$ 2,028
Accretion expense	266	287
Total	2,580	2,315
Less: current portion of asset retirement obligations	(2,580)	(2,315)
Long-term asset retirement obligations, at the end of the period	$ 0	$ 0

13. Impairment (Details Narrati

13. Impairment (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Impairment Details Narrative Abstract
Impairment expense	$ 0	$ 303

14. Treasury Stock (Details Nar

14. Treasury Stock (Details Narrative) - shares	Dec. 31, 2018	Dec. 31, 2017
Treasury Stock Details Narrative Abstract
Treasury stock	0	0

15. Concentration of Risk (Deta

15. Concentration of Risk (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Total refined petroleum product sales	$ 337,038	$ 255,547
Concentration Risk	100.00%	100.00%
LPG mix [Member]
Total refined petroleum product sales	$ 3	$ 12
Concentration Risk	0.00%	0.00%
Naphtha
Total refined petroleum product sales	$ 82,982	$ 60,408
Concentration Risk	24.60%	23.60%
Jet Fuel [Member]
Total refined petroleum product sales	$ 98,570	$ 81,094
Concentration Risk	29.20%	31.70%
HOBM [Member]
Total refined petroleum product sales	$ 80,979	$ 54,851
Concentration Risk	24.10%	21.50%
AGO [Member]
Total refined petroleum product sales	$ 74,504	$ 59,071
Concentration Risk	22.10%	23.20%

15. Concentration of Risk (De_2

15. Concentration of Risk (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250	$ 250
Excess of the FDIC insurance limit	$ 1,200	$ 1,600
Sales Revenue [Member] | Four customers [Member]
Concentration Risk	91.00%
Sales Revenue [Member] | Three customers [Member]
Concentration Risk		70.00%
Sales Revenue [Member] | LEH [Member]
Concentration Risk	29.00%
Account receivable [Member] | Four customers [Member]
Accounts receivable	$ 100
Account receivable [Member] | Three customers [Member]
Accounts receivable		$ 1,300
Account receivable [Member] | LEH [Member]
Concentration Risk	33.00%
Accounts receivable	$ 700

16. Leases (Details)

16. Leases (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases Details 1
2019	$ 190
2020	230
2021	233
2022	237
2023	161
Leases Futurre Minimum Payment, Net	$ 1,051

16. Leases (Details Narrative)

16. Leases (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Leases Details Narrative Abstract
Rent expense	$ 200	$ 200

17. Income Taxes (Details)

17. Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Current
Federal	$ 108	$ 0
State	43	0
Deferred
Impact of change in enacted tax rates	0	(6,654)
Change in valuation allowance	109	6,654
Total provision for income taxes	$ 260	$ 0

17. Income Taxes (Details 1)

17. Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Taxes Details Narrative Abstract
Expected tax rate	(21.00%)	(34.00%)
Permanent differences	0.00%	0.00%
State tax	(5.10%)	0.00%
Federal tax	(28.10%)	0.00%
Change in valuation allowance	21.00%	34.00%
Expected tax rate Continuing Operations	(33.20%)	0.00%

17. Income Taxes (Details 2)

17. Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 11,260	$ 9,767
Accrued arbitration award payable	(21,128)	(27,128)
Business interest expense	704	0
Start-up costs (Nixon Facility)	678	763
Asset retirement obligations liability/deferred revenue	542	495
AMT credit and other	108	217
Total deferred tax assets	16,142	15,365
Deferred tax liabilities:
Basis differences in property and equipment	(5,153)	(4,415)
Total deferred tax liabilities	(5,153)	(4,415)
Deferred tax assets, net	10,989	10,950
Valuation allowance	(10,881)	(10,950)
Deferred tax assets, net	$ 108	$ 0

17. Income Taxes (Details 3)

17. Income Taxes (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Balance	$ 39,833	$ 33,177
Net operating losses generated post-acquisition	7,106	6,656
Balance	46,939	39,833
Pre-Ownership Change [Member]
Balance	9,614	9,614
Net operating losses generated post-acquisition	0	0
Balance	9,614	9,614
Post-Ownership Change [Member]
Balance	30,219	23,563
Net operating losses generated post-acquisition	7,106	6,656
Balance	$ 37,325	$ 30,219

18. Earnings per share (Details

18. Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Net income (loss)	$ (523)	$ (22,328)
Basic and diluted income (loss) per share	$ (0.05)	$ (2.09)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	(0.05)	(2.09)