Blue Dolphin Energy (BDCO) 10-Q 15 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 15, 2018
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-Q
Document Period End Date	Mar. 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	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,925,513
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2,018

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 733	$ 495
Restricted cash	49	49
Accounts receivable, net	539	1,357
Accounts receivable, related party	346	653
Prepaid expenses and other current assets	1,430	1,207
Deposits	145	129
Inventory	2,323	3,089
Refundable federal income tax	108	0
Total current assets	5,673	6,979
Total property and equipment, net	64,764	64,597
Restricted cash, noncurrent	1,602	1,602
Surety bonds	230	230
Deferred tax assets, net	109	0
Total long-term assets	66,705	66,429
TOTAL ASSETS	72,378	73,408
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion	35,387	35,544
Long-term debt, related party, current portion	5,825	4,000
Interest payable, current portion	2,337	2,135
Interest payable, related party, current portion	1,052	892
Accounts payable	1,786	2,344
Accounts payable, related party	1,126	974
Asset retirement obligations, current portion	2,381	2,315
Accrued expenses and other current liabilities	1,679	1,160
Accrued arbitration award payable	25,628	27,128
Total current liabilities	77,201	76,492
Long-term liabilities:
Asset retirement obligations, net of current portion	0	0
Deferred revenues and expenses	31	42
Capital lease obligation, net of current portion	31	0
Long-term debt, related party, net of current portion	0	1,608
Total long-term liabilities	62	1,650
TOTAL LIABILITIES	77,263	78,142
Commitments and contingencies (Note 17)
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,925,513 shares issued at March 31, 2018 and December 31, 2017, respectively)	109	109
Additional paid-in capital	36,907	36,907
Accumulated deficit	(41,901)	(41,750)
Total stockholders' equity (deficit)	(4,885)	(4,734)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)	$ 72,378	$ 73,408

Consolidated Balance Sheets (U3

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 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
Common stock, shares issued	10,925,513	10,925,513
Common stock, shares Outstanding	10,925,513	10,925,513

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUE FROM OPERATIONS
Refinery operations	$ 71,512	$ 51,902
Tolling and terminaling	734	704
Total revenue from operations	72,246	52,606
COST OF OPERATIONS
Cost of refined products sold	68,724	51,775
Refinery operating expenses	1,922	2,813
Other operating expenses	44	61
General and administrative expenses	660	906
Depletion, depreciation and amortization	455	451
Accretion of asset retirement obligations	66	72
Total cost of operations	71,871	56,078
Income (loss) from operations	375	(3,472)
OTHER INCOME (EXPENSE)
Easement, interest and other income	1	382
Interest and other expense	(744)	(595)
Gain on disposal of property	0	1,835
Total other income (expense)	(743)	1,622
Loss before income taxes	(368)	(1,850)
Income tax benefit	217	0
Net loss	$ (151)	$ (1,850)
Loss per common share:
Basic	$ (0.01)	$ (0.18)
Diluted	$ (0.01)	$ (0.18)
Weighted average number of common shares outstanding:
Basic	10,925,513	10,474,714
Diluted	10,925,513	10,474,714

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
OPERATING ACTIVITIES
Net loss	$ (151)	$ (1,850)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	455	451
Deferred income tax	(109)	0
Amortization of debt issue costs	32	32
Accretion of asset retirement obligations	66	72	$ 287
Changes in operating assets and liabilities
Accounts receivable	818	1,816
Accounts receivable, related party	307	1,162
Prepaid expenses and other current assets	(331)	(554)
Deposits and other assets	(16)	(25)
Inventory	766	(2,334)
Accrued arbitration award	(1,500)	0
Accounts payable, accrued expenses and other liabilities	312	(1,294)
Accounts payable, related party	152	151
Net cash provided by (used in) operating activities	801	(2,373)
INVESTING ACTIVITIES
Capital expenditures	(540)	(811)
Net cash used in investing activities	(540)	(811)
FINANCING ACTIVITIES
Payments on debt	(240)	(474)
Net activity on related-party debt	217	1,097
Net cash provided by financing activities	(23)	623
Net change in cash, cash equivalents, and restricted cash	238	(2,561)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	2,146	6,083	6,083
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	2,384	3,522	$ 2,146
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	82	1,220
Financing of guaranty fees via long-term debt, related party	163	183
Conversion of accounts payable to short-term notes	0	90
Interest paid	558	559
Income taxes paid	$ 0	$ 0

1. Organization

1. Organization	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations Pipeline transportation and oil and gas operations are no longer active. Structure and Management We have the following active subsidiaries: ● Lazarus Energy, LLC, a Delaware limited liability company (“LE”). ● Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”). ● Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”). ● Blue Dolphin Petroleum Company, a Delaware corporation. ● Blue Dolphin Services Co., a Texas corporation (“BDSC”). See "Part I, Item 1. Business” and “Item 2. Properties” in the Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets. References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires. Going Concern ● Final Arbitration Award – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of approximately $31.3 million. As of the date of this report, LE has paid $6.2 million to GEL, which amount has been applied to reduce the balance of the Final Arbitration Award. As previously disclosed, a hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for a period of no more than 90 days after September 18, 2017 (the “Continuance Period”), to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into a Letter Agreement with GEL, effective September 18, 2017 (the “GEL Letter Agreement”), confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement. The GEL Letter Agreement has been amended to extend the Continuance Period through May 31, 2018. The GEL Letter Agreement, as amended to date, prohibits Blue Dolphin and its affiliates from making any pre-payments on indebtedness, other than in the ordinary course of business as described in the GEL Letter Agreement, and from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements between November 1, 2017 and the end of the Continuance Period. (Jonathan Carroll has received no cash payments since August 2016 and no common stock payments since May 2017 under the Amended and Restated Guaranty Fee Agreements.) We can provide no assurance as to whether negotiations with GEL will result in a settlement or the potential terms of any such settlement. If the parties are unable to reach an acceptable settlement with GEL, and GEL seeks to confirm and enforce the Final Arbitration Award: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) LE would likely be required to seek protection under bankruptcy laws. ● Veritex Secured Loan Agreement Event of Default – Veritex Community Bank (“Veritex”), as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all 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 loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at March 31, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future. We can provide no assurance as to whether Veritex, as first lienholder, would approve a settlement between GEL and the parties related to the Final Arbitration Award. If the parties are unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and LE would likely be required to seek protection under bankruptcy laws. Further, any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations, and LE would likely be required to seek protection under bankruptcy laws. Operating Risks ● Net Losses – For the quarter ended March 31, 2018, we reported a net loss of $0.2 million, or a loss of $0.01 per share, compared to a net loss of $1.9 million, or a loss of $0.18 per share, for the year ended March 31, 2017. The $0.17 per share decrease in net loss between the periods was the result of improved margins for refined petroleum products and increased sales volume. ● Working Capital Deficits – We had a working capital deficit of $71.5 million at March 31, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $30.3 million at March 31, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017. ● Crude Supply – 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, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which could be adversely affected if the parties are unable to reach an acceptable settlement with GEL, and GEL seeks to confirm and enforce the Final Arbitration Award, and other factors, as noted above. ● Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at March 31, 2018, LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at March 31, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to any proposed settlement with GEL, or provide future waivers of any financial covenant defaults, which would have an adverse impact on our financial position and results of operations. We are continuing aggressive actions in 2018 to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability. However, there can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. If the parties are unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and LE would likely be required to seek protection under bankruptcy laws. For additional disclosures related to the Final Arbitration Award, the GEL Letter Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Quarterly Report: ● Part I, Item 1. Financial Statements, Notes to Consolidated Financial Statements: - Note (8) Related Party Transactions - Note (10) Long-Term Debt, Net - Note (17) Commitments and Contingencies – Legal Matters - Note (18) Subsequent Events ● Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: - Final Arbitration Award - Results of Operations - Liquidity and Capital Resources ● Part II, Item 1. Legal Proceedings ● Part II, Item 1A. Risk Factors

2. Basis of Presentation

2. Basis of Presentation	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	The accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading. The consolidated balance sheet as of December 31, 2017 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report. Operating results for the three months ended March 31, 2018 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2018, or for any other period.

3. Significant Accounting Polic

3. Significant Accounting Policies	3 Months Ended
	Mar. 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 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (7) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.) Intangibles – Other Debt Issue Costs Revenue Recognition We adopted the provisions of FASB ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services do not provide a material right to the customer, and such services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period. Income Taxes As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of March 31, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At March 31, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (15) 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 (11) 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 (16) Earnings Per Share” for additional information related to EPS.) Treasury Stock New Pronouncements Adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) New Pronouncements Issued, Not Yet Effective ASU 2018-05, Income Taxes (Topic 740) ASU 2016-02, Leases (Topic 842) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Business Segment Information

4. Business Segment Information	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Business Segment Information	We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility. Business segment information for the periods indicated (and as of the dates indicated), was as follows: Three Months Ended March 31, 2018 2017 Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 71,512 $ 734 $ — $ 72,246 $ 52,606 $ — $ 52,606 Intersegment revenues — 671 — 671 — — — Less: operation costs (1) (70,915 ) (728 ) (444 ) (72,087 ) (55,196 ) (430 ) (55,626 ) Other non-interest income (2) — — — — — 2,216 2,216 EBITDA (3) $ 597 $ 677 $ (444 ) $ (2,590 ) $ 1,786 Depletion, depreciation and amortization (455 ) (451 ) Interest expense, net (743 ) (595 ) Loss before income taxes (368 ) (1,850 ) Income tax benefit 217 — Net loss $ (151 ) $ (1,850 ) Capital expenditures $ 418 $ 204 $ — $ 622 $ 2,031 $ — $ 2,031 Identifiable assets $ 53,207 $ 18,912 $ 259 $ 72,378 $ 73,247 $ 1,068 $ 74,315 (1) Operation costs within Refinery Operations includes related general and administrative expenses. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, directors fees, and legal expense), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Other non-interest income reflects FLNG Land II, Inc. easement revenue. See “Note (17) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG. (3) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

5. Prepaid Expenses and Other C

5. Prepaid Expenses and Other Current Assets	3 Months Ended
	Mar. 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: March 31, December 31, 2018 2017 (in thousands) Prepaid crude oil and condensate $ 1,300 $ 913 Prepaid insurance 130 294 $ 1,430 $ 1,207

6. Inventory

6. Inventory	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) Crude oil and condensate $ 1,080 $ 961 HOBM 594 1,558 AGO 309 213 Chemicals 165 162 Naphtha 145 170 Propane 22 17 LPG mix 8 8 $ 2,323 $ 3,089

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	3 Months Ended
	Mar. 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: March 31, December 31, 2018 2017 (in thousands) Refinery and facilities $ 51,662 $ 51,432 Land 566 566 Other property and equipment 747 653 52,975 52,651 Less: Accumulated depletion, depreciation, and amortization (8,951 ) (8,495 ) 44,024 44,156 Construction in progress 20,740 20,441 $ 64,764 $ 64,597 We capitalize interest cost incurred on funds used to construct property, plant, and equipment. The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $4.2 million and $3.9 million at March 31, 2018 and December 31, 2017, respectively. We expect construction of petroleum storage tanks at the Nixon Facility to continue to year end.

8. Related Party Transactions

8. Related Party Transactions	3 Months Ended
	Mar. 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. Each quarter amounts owed by the parties are settled with amounts to be paid by the parties as discussed within this Note (8) Related Party Transactions. As a result, related-party transactions do not always reflect cash payments between the parties. Operations Related Agreements . Amended and Restated Operating Agreement Jet Fuel Sales Agreement Terminal Services Agreement Amended and Restated Tank Lease Agreement Dock Tolling Agreement Financial Agreements . Loan BDPL 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 BDPL 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 Pursuant to the GEL Letter Agreement, as amended to date, Blue Dolphin and its affiliates shall: (i) pay only debts in the ordinary course of business as described in the GEL Letter Agreement, (ii) refrain from making pre-payments on indebtedness, and (iii) suspend payments to Jonathan Carroll under Guaranty Fee Agreements. As a result, no payments were made under the BDPL Loan Agreement, the March Ingleside Note, and the March Carroll Note during the three months ended March 31, 2018. Debt Assumption Agreement Amended and Restated Guaranty Fee Agreements Pursuant to the GEL Letter Agreement, as amended to date, Blue Dolphin and its affiliates shall: (i) pay only debts in the ordinary course of business as described in the GEL Letter Agreement, (ii) refrain from making pre-payments on indebtedness, and (iii) suspend payments to Jonathan Carroll under Guaranty Fee Agreements. As a result, Jonathan Carroll received no cash payments and no common stock payments during the three months ended March 31, 2018. (See “Note (10) Long-Term Debt, Net” for further discussion related to these guaranty fee agreements.) Financial Statements Impact Consolidated Balance Sheets Long-term debt, related party associated with the BDPL Loan Agreement, March Ingleside Note, and March Carroll Note as of the dates indicated was as follows: March 31, December 31, 2018 2017 (in thousands) LEH $ 4,000 $ 4,000 Ingleside 1,215 1,169 Jonathan Carroll 610 439 5,825 5,608 Less: Long-term debt, related party, current portion (5,825 ) (4,000 ) $ — $ 1,608 Accrued interest associated with the BDPL Loan Agreement was $1.1 million and $0.9 million at March 31, 2018 and December 31, 2017, respectively. Consolidated Statements of Operations Three Months Ended March 31, 2018 2017 (in thousands, except percent amounts) LEH Jet fuel product sales $ 20,567 28.8 % $ 18,769 36.2 % Other customers Product sales 50,945 71.2 % 33,133 63.8 % $ 71,512 100.0 % $ 51,902 100.0 % Related party cost of goods sold associated with the Dock Tolling Agreement with LMT totaled $0.2 million for both the three months ended March 31, 2018 and 2017. Related party refinery operating expenses associated with the Amended and Restated Operating Agreement with LEH for the periods indicated were as follows: Three Months Ended March 31, 2018 2017 Throughput Throughput Amount per bbl Amount per bbl (in thousands, except per bbl amounts) LEH $ 1,922 $ 1.91 $ 2,813 $ 2.80 $ 1,922 $ 1.91 $ 2,813 $ 2.80 For the three months ended March 31, 2018, refinery operating expenses per bbl decreased $0.89 per bbl compared to the same period a year earlier. The decrease was due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement, as well as management’s efforts to reduce overall operating costs. Related party interest expense associated with the BDPL Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows: Three Months Ended March 31, 2018 2017 (in thousands) Jonathan Carroll $ 163 $ 168 LEH 160 207 Ingleside 47 — $ 370 $ 375

9. Accrued Expenses and Other C

9. Accrued Expenses and Other Current Liabilities	3 Months Ended
	Mar. 31, 2018
Disclosure Text Block Supplement [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) Unearned revenue $ 942 $ 450 Board of director fees payable 239 207 Other payable 145 116 Customer deposits 109 109 Insurance 89 68 Excise and income taxes payable 83 79 Property taxes 72 131 $ 1,679 $ 1,160

10. Long-Term Debt, Net

10. Long-Term Debt, Net	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt, Net	Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 23,020 $ 23,199 Second Term Loan Due 2034 (in default) 9,450 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 72 — $ 37,520 $ 37,679 Less: Current portion of long-term debt, net (35,387 ) (35,544 ) Less: Unamortized debt issue costs (2,102 ) (2,135 ) $ 31 $ — Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following: March 31, 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 (340 ) (307 ) $ 2,102 $ 2,135 Amortization expense was $0.03 million for both the three months ended March 31, 2018 and 2017. Accrued interest associated with long-term debt, net is reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets and includes related party interest. Accrued interest as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,245 $ 2,046 LEH Loan Agreement (related party) 1,052 892 Second Term Loan Due 2034 (in default) 51 49 First Term Loan Due 2034 (in default) 41 40 3,389 3,027 Less: Interest payable, current portion (3,389 ) (3,027 ) Long-term interest payable, net of current portion $ — $ — Related Party First Term Loan Due 2034 (In Default) a term loan in the principal amount of $25.0 million As described elsewhere in this Annual Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at March 31, 2018, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require LE to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee r epayment A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a payment reserve account held by Veritex, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Second Term Loan Due 2034 (In Default) As described elsewhere in this Annual Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at December 31, 2017, LRM was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the Second Term Loan Due 2034. The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the ongoing settlement discussions with GEL and the continuance of the hearing on confirmation of the Final Arbitration Award and to allow Veritex to evaluate any proposed settlement agreement related to the Final Arbitration Award, which would require Veritex’s approval. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require LE to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the Second Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.1 million for both the three months ended March 31, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. The GEL Letter Agreement, as amended to date, prohibits Blue Dolphin and its affiliates from making any payments to Jonathan Carroll under the Amended and Restated Guaranty Fee Agreements. As a result, Jonathan Carroll received no cash payments and no common stock payments during the three months ended March 31, 2018. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Notre Dame Debt (In Default) The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Capital Leases Boiler Equipment Lease Crane Lease A summary of equipment held under long-term capital leases as of the dates indicated follows: March 31, December 31, 2018 2017 (in thousands) Crane $ 94 $ — Less: accumulated depreciation (3 ) — $ 91 $ —

11. Asset Retirement Obligation

11. Asset Retirement Obligations	3 Months Ended
	Mar. 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: March 31, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 66 287 2,381 2,315 Less: asset retirement obligations, current portion (2,381 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ — $ —

12. Treasury Stock

12. Treasury Stock	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Treasury Stock	At March 31, 2018 and 2017, we had 0 and 150,000 shares of treasury stock, respectively. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

13. Concentration of Risk

13. Concentration of Risk	3 Months Ended
	Mar. 31, 2018
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier 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, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which could be adversely affected if the parties are unable to reach an acceptable settlement with GEL, and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements. Significant Customers For the three months ended March 31, 2018, we had 3 customers that accounted for approximately 77.0% of refinery operations revenue. LEH was 1 of these 3 significant customers and accounted for approximately 28.8% of refinery operations revenue. At March 31, 2018, these 3 customers represented approximately $0.3 million in accounts receivable. LEH represented approximately $0.3 million in accounts receivable. LEH, which is HUBZone certified, purchases our jet fuel and resells the jet fuel to a government agency. (See “Note (8) Related Party Transactions,” “Note (10) Long-Term Debt, Net,” and “Note (17) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.) For the three months ended March 31, 2017, we had 3 customers that accounted for approximately 82.1% of refinery operations revenue. LEH was 1 of these 3 significant customers and accounted for approximately 36.2% of refinery operations revenue. At March 31, 2017, these 3 customers represented approximately $0 in accounts receivable. Refined Petroleum Product Sales Three Months Ended March 31, 2018 2017 LPG mix $ 3 0.0 % $ 120 0.2 % Naphtha 16,318 22.8 % 13,763 26.5 % Jet fuel 20,567 28.8 % 15,400 29.7 % HOBM 16,429 23.0 % 10,686 20.6 % AGO 18,195 25.4 % 11,933 23.0 % $ 71,512 100.0 % $ 51,902 100.0 %

14. Leases

14. Leases	3 Months Ended
	Mar. 31, 2018
Leases, Operating [Abstract]
Leases	BDSC leases our principal office space in Houston, Texas under a 2006 lease agreement. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that extended the lease period by sixty-eight (68) months expiring on August 31, 2023. Under the Lease Amendment, our base rent for 6,489 square feet is $0.01 million per month. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For the three months ended March 31, 2018 and 2017, rent expense totaled $0.05 million and $0.03 million, respectively. Rent expense is recognized on a straight-line basis.

15. Income Taxes

15. Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The principal element of the Tax Cuts and Jobs Act relevant to our financial statements is a reduction in the U.S. federal corporate tax rate from 34% to 21%, effective January 1, 2018. Other provisions of the Tax Cuts and Jobs Act did not have a significant impact on our financial statements for the three months ended March 31, 2018. For the three months ended March 31, 2018 and 2017, we recognized an income tax benefit of $0.2 million and $0, respectively. The provision for income tax benefit (expense) as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) Current $ 108 $ — Deferred Impact of change in enacted tax rates — (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 217 $ — In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to Alternative Minimum Tax credits made refundable by the Tax Cuts and Jobs Act. In 2017, our effective tax rate differed from the U.S. federal statutory rate primarily due to re-measuring deferred income taxes at the new statutory tax rate and the related change of the valuation allowance over our deferred tax assets. At the date of enactment of the Tax Cuts and Jobs Act, we re-measured our deferred tax assets and liabilities using a rate of 21%, which is the rate expected to be in place when such deferred assets and liabilities are expected to reverse in the future. The re-measurement, which was offset by a change in our valuation allowance, reduced our net deferred tax assets by approximately $6.7 million. 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. Deferred income taxes as of the dates indicated consisted of the following: March 31, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,720 $ 9,767 Accrued arbitration award payable 3,377 4,122 Start-up costs (crude oil and condensate processing facility) 742 763 Asset retirement obligations liability/deferred revenue 507 495 AMT credit and other 109 217 Total deferred tax assets 15,455 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,577 ) (4,415 ) Total deferred tax liabilities (4,577 ) (4,415 ) 10,878 10,950 Valuation allowance (10,769 ) (10,950 ) Deferred tax assets, net $ 109 $ — Deferred Income Taxes NOL Carryforwards NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused because of the IRC Section 382 limitation): Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses — 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses — 4,295 4,295 Balance at March 31, 2018 $ 9,614 $ 34,513 $ 44,127 Valuation Allowance

16. Earnings Per Share

16. Earnings Per Share	3 Months Ended
	Mar. 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: Three Months Ended March 31, 2018 2017 (in thousands, except share and per share amounts) Net loss $ (151 ) $ (1,850 ) Basic and diluted income per share $ (0.01 ) $ (0.18 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,474,714 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three months ended March 31, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

17. Commitments and Contingenci

17. Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Matters Final Arbitration Award Veritex Secured Loan Agreement Event of Default Other Legal Matters Amended and Restated Operating Agreement FLNG Easements Financing Agreements Guarantees Health, Safety and Environmental Matters Nixon Facility Expansion Supplemental Pipeline Bonds

18. Subsequent Events

18. Subsequent Events	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Seventh Amendment to GEL Letter Agreement

3. Significant Accounting Pol24

3. Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Use of Estimates	We have made several estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. We believe our current estimates are reasonable and appropriate, however, actual results could differ from those estimated.
Cash and Cash Equivalents	Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
Restricted Cash	Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks.
Accounts Receivable and Allowance for Doubtful Accounts	Our accounts receivable consists of customer obligations due in the ordinary course of business. Since we have a small number of customers with individually large amounts due on any given date, we evaluate potential and existing customers’ financial condition, credit worthiness, and payment history to minimize credit risk. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods. If necessary, we establish an allowance for doubtful accounts to estimate the amount of probable credit losses. Allowance for doubtful accounts totaled $0 both at March 31, 2018 and December 31, 2017.
Inventory	Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See “Note (6) Inventory” for additional disclosures related to our inventory.)
Property and Equipment	Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (7) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.)
Intangibles - Other	Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name. We account for intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we determined trade name to have an indefinite useful life, and we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2017. Upon completion of that testing, our trade name asset was fully impaired at December 31, 2017.
Debt Issue Costs	We have debt issue costs related to certain refinery and facilities assets debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. Debt issue costs are presented net with the related debt liability. (See “Note (10) Long-Term Debt, Net” for additional disclosures related to debt issue costs.)
Revenue Recognition	We adopted the provisions of FASB ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services do not provide a material right to the customer, and such services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period.
Income Taxes	As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of March 31, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At March 31, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (15) Income Taxes” for further information related to income taxes.)
Impairment or Disposal of Long-Lived Assets	In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the quarter ended March 31, 2018.
Asset Retirement Obligations	FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (11) Asset Retirement Obligations” for additional information related to our AROs.)
Computation of Earnings Per Share	We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (16) Earnings Per Share” for additional information related to EPS.)
Treasury Stock	We accounted for treasury stock under the cost method. In May 2017, our treasury stock was re-issued. The net change in share price after acquisition of the treasury stock was recognized as a component of additional paid-in-capital in our consolidated balance sheets. (See “Note (12) Treasury Stock” for additional disclosures related to treasury stock.)
New Pronouncements Adopted	The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include: ASU 2014-09, Revenue from Contracts with Customers (ASC 606)
New Pronouncements Issued but Not Yet Effective	The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows: ASU 2018-05, Income Taxes (Topic 740) ASU 2016-02, Leases (Topic 842) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.

4. Business Segment Informati25

4. Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Business segment reporting	Three Months Ended March 31, 2018 2017 Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 71,512 $ 734 $ — $ 72,246 $ 52,606 $ — $ 52,606 Intersegment revenues — 671 — 671 — — — Less: operation costs (1) (70,915 ) (728 ) (444 ) (72,087 ) (55,196 ) (430 ) (55,626 ) Other non-interest income (2) — — — — — 2,216 2,216 EBITDA (3) $ 597 $ 677 $ (444 ) $ (2,590 ) $ 1,786 Depletion, depreciation and amortization (455 ) (451 ) Interest expense, net (743 ) (595 ) Loss before income taxes (368 ) (1,850 ) Income tax benefit 217 — Net loss $ (151 ) $ (1,850 ) Capital expenditures $ 418 $ 204 $ — $ 622 $ 2,031 $ — $ 2,031 Identifiable assets $ 53,207 $ 18,912 $ 259 $ 72,378 $ 73,247 $ 1,068 $ 74,315 (1) Operation costs within Refinery Operations includes related general and administrative expenses. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, directors fees, and legal expense), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Other non-interest income reflects FLNG Land II, Inc. easement revenue. See “Note (17) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG. (3) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA.

5. Prepaid Expenses and Other26

5. Prepaid Expenses and Other Current Assets (Tables)	3 Months Ended
	Mar. 31, 2018
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid balances	March 31, December 31, 2018 2017 (in thousands) Prepaid crude oil and condensate $ 1,300 $ 913 Prepaid insurance 130 294 $ 1,430 $ 1,207

6. Inventory (Tables)

6. Inventory (Tables)	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventory	March 31, December 31, 2018 2017 (in thousands) Crude oil and condensate $ 1,080 $ 961 HOBM 594 1,558 AGO 309 213 Chemicals 165 162 Naphtha 145 170 Propane 22 17 LPG mix 8 8 $ 2,323 $ 3,089

7. Property, Plant and Equipm28

7. Property, Plant and Equipment, Net (Tables)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Property and equipment	March 31, December 31, 2018 2017 (in thousands) Refinery and facilities $ 51,662 $ 51,432 Land 566 566 Other property and equipment 747 653 52,975 52,651 Less: Accumulated depletion, depreciation, and amortization (8,951 ) (8,495 ) 44,024 44,156 Construction in progress 20,740 20,441 $ 64,764 $ 64,597

8. Related Party Transactions (

8. Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Accounts Payable, Related Party	March 31, December 31, 2018 2017 (in thousands) LEH $ 4,000 $ 4,000 Ingleside 1,215 1,169 Jonathan Carroll 610 439 5,825 5,608 Less: Long-term debt, related party, current portion (5,825 ) (4,000 ) $ — $ 1,608
Accrued interest Expenses	Three Months Ended March 31, 2018 2017 (in thousands, except percent amounts) LEH Jet fuel product sales $ 20,567 28.8 % $ 18,769 36.2 % Other customers Product sales 50,945 71.2 % 33,133 63.8 % $ 71,512 100.0 % $ 51,902 100.0 %
Refinery operating expenses	Three Months Ended March 31, 2018 2017 Throughput Throughput Amount per bbl Amount per bbl (in thousands, except per bbl amounts) LEH $ 1,922 $ 1.91 $ 2,813 $ 2.80 $ 1,922 $ 1.91 $ 2,813 $ 2.80 Three Months Ended March 31, 2018 2017 (in thousands) Jonathan Carroll $ 163 $ 168 LEH 160 207 Ingleside 47 - $ 370 $ 375

9. Accrued Expenses and Other30

9. Accrued Expenses and Other Current Liabilities (Tables)	3 Months Ended
	Mar. 31, 2018
Disclosure Text Block Supplement [Abstract]
Accrued expenses and other current liabilities	March 31, December 31, 2018 2017 (in thousands) Unearned revenue $ 942 $ 450 Board of director fees payable 239 207 Other payable 145 116 Customer deposits 109 109 Insurance 89 68 Excise and income taxes payable 83 79 Property taxes 72 131 $ 1,679 $ 1,160

10. Long-Term Debt, Net (Tables

10. Long-Term Debt, Net (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long Term Debt	March 31, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 23,020 $ 23,199 Second Term Loan Due 2034 (in default) 9,450 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 72 — $ 37,520 $ 37,679 Less: Current portion of long-term debt, net (35,387 ) (35,544 ) Less: Unamortized debt issue costs (2,102 ) (2,135 ) $ 31 $ —
Schedule of Debt issue costs	March 31, 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 (340 ) (307 ) $ 2,102 $ 2,135
Accrued interest related to our long-term debt, net	March 31, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,245 $ 2,046 LEH Loan Agreement (related party) 1,052 892 Second Term Loan Due 2034 (in default) 51 49 First Term Loan Due 2034 (in default) 41 40 3,389 3,027 Less: Interest payable, current portion (3,389 ) (3,027 ) Long-term interest payable, net of current portion $ — $ —
Schedule of summary of equipment held under long-term capital leases	March 31, December 31, 2018 2017 (in thousands) Crane $ 94 $ — Less: accumulated depreciation (3 ) — $ 91 $ —

11. Asset Retirement Obligati32

11. Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	March 31, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 66 287 2,381 2,315 Less: asset retirement obligations, current portion (2,381 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ — $ —

13. Concentration of Risk (Tabl

13. Concentration of Risk (Tables)	3 Months Ended
	Mar. 31, 2018
Risks and Uncertainties [Abstract]
Percentages of all refined petroleum products sales to total sales	Three Months Ended March 31, 2018 2017 LPG mix $ 3 0.0 % $ 120 0.2 % Naphtha 16,318 22.8 % 13,763 26.5 % Jet fuel 20,567 28.8 % 15,400 29.7 % HOBM 16,429 23.0 % 10,686 20.6 % AGO 18,195 25.4 % 11,933 23.0 % $ 71,512 100.0 % $ 51,902 100.0 %

15. Income Taxes (Tables)

15. Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	March 31, December 31, 2018 2017 (in thousands) Current $ 108 $ — Deferred Impact of change in enacted tax rates — (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 217 $ —
Deferred tax assets and deferred tax liabilities	March 31, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,720 $ 9,767 Accrued arbitration award payable 3,377 4,122 Start-up costs (crude oil and condensate processing facility) 742 763 Asset retirement obligations liability/deferred revenue 507 495 AMT credit and other 109 217 Total deferred tax assets 15,455 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,577 ) (4,415 ) Total deferred tax liabilities (4,577 ) (4,415 ) 10,878 10,950 Valuation allowance (10,769 ) (10,950 ) Deferred tax assets, net $ 109 $ —
NOL carryforwards	Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses — 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses — 4,295 4,295 Balance at March 31, 2018 $ 9,614 $ 34,513 $ 44,127

16. Earnings Per Share (Tables)

16. Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings per share	Three Months Ended March 31, 2018 2017 (in thousands, except share and per share amounts) Net loss $ (151 ) $ (1,850 ) Basic and diluted income per share $ (0.01 ) $ (0.18 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,474,714

1. Organization (Details Narrat

1. Organization (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss)	$ (151)	$ (1,850)
Net Loss per common share	$ (0.01)	$ (0.18)
Working capital deficit current portion	$ (71,500)		$ (69,500)
Working capital deficit payment of Operations	$ (30,300)		$ (30,000)

3. Significant Accounting Pol37

3. Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Accounting Policies [Abstract]
Restricted cash (current portion)	$ 49		$ 49
Restricted cash, noncurrent	1,602		$ 1,602
Gain on the disposal of property	$ 0	$ 1,835

4. Business Segment Informati38

4. Business Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenue from operations	$ 72,246	$ 52,606
Depletion, depreciation and amortization	(30)	(30)
Income tax benefit	(217)	0	$ 0
Net loss	(151)	(1,850)
Refinery Operations [Member]
Revenue from operations	71,512	52,606
Less: cost of operations (1)	0	0
Other non-interest income (2)	(70,915)	(55,196)
Less: JMA Profit Share (3)	0	0
EBITDA (4)	597	(2,590)
Capital expenditures	418	2,031
Identifiable assets	53,207	73,247
Tolling and Terminaling [Member]
Revenue from operations	734
Less: cost of operations (1)	671
Other non-interest income (2)	(728)
Less: JMA Profit Share (3)	0
EBITDA (4)	677
Capital expenditures	204
Identifiable assets	18,912
Corporate & Other [Member]
Revenue from operations	0	0
Less: cost of operations (1)	0	0
Other non-interest income (2)	(444)	(430)
Less: JMA Profit Share (3)	0	2,216
EBITDA (4)	444	1,786
Capital expenditures	0	0
Identifiable assets	259	1,068
Total
Revenue from operations	72,246	52,606
Less: cost of operations (1)	671	0
Other non-interest income (2)	(72,087)	(55,626)
Less: JMA Profit Share (3)	0	2,216
Depletion, depreciation and amortization	(455)	(451)
Interest expense, net	(743)	(595)
Loss before income taxes	(368)	(1,850)
Income tax benefit	217	0
Net loss	(151)	(1,850)
Capital expenditures	622	2,031
Identifiable assets	$ 72,378	$ 74,315

5. Prepaid Expenses and Other39

5. Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid crude oil and condensate	$ 1,300	$ 913
Prepaid insurance	130	294
Prepaid expenses, net	$ 1,430	$ 1,207

6. Inventory (Details)

6. Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and condensate	$ 1,080	$ 961
HOBM	594	1,558
AGO	309	213
Chemicals	165	162
Naphtha	145	170
Propane	22	17
LPG mix	8	8
Inventories, net	$ 2,323	$ 3,089

7. Property, Plant and Equipm41

7. Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 51,662	$ 51,432
Land	566	566
Other property and equipment	747	653
Property, Plant and Equipment, Gross	52,975	52,651
Less: Accumulated depletion, depreciation and amortization	(8,951)	(8,495)
Property, plant and equipment, gross	44,024	44,156
Construction in progress	20,740	20,441
Property, plant and equipment, net	$ 64,764	$ 64,597

7. Property, Plant and Equipm42

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

8. Related Party Transactions43

8. Related Party Transactions (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Prepaid operating expenses, related party	$ 5,825	$ 5,608
Less: Long-term debt - current portion, related party	(5,825)	(4,000)
Long-term debt - net of current portion, related party	0	1,608
LEH [Member]
Prepaid operating expenses, related party	4,000	4,000
Ingleside [Member]
Prepaid operating expenses, related party	1,215	1,169
Jonathan Carroll [Member]
Prepaid operating expenses, related party	$ 610	$ 439

8. Related Party Transactions44

8. Related Party Transactions (Details 1) - LEH [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Jet fuel sales	$ 20,567	$ 18,769
Product sales	50,945	33,133
Total	$ 71,512	$ 51,902
Jet fuel sales, percentage	28.80%	36.20%
Product sales, percentage	71.20%	63.80%
Total, percentage	100.00%	100.00%

8. Related Party Transactions45

8. Related Party Transactions (Details 2) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)$ / bbl	Mar. 31, 2017USD ($)$ / bbl
Refinery operating expenses, Amount | $	$ 1,922	$ 2,813
Refinery operating expenses, Per bbl | $ / bbl	1.91	2.8
LEH [Member]
Refinery operating expenses, Amount | $	$ 1,922	$ 2,813
Refinery operating expenses, Per bbl | $ / bbl	1.91	2.8

8. Related Party Transactions46

8. Related Party Transactions (Details 3) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Interest expenses under loan and guarantee, related party	$ 370	$ 375
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	163	168
LEH [Member]
Interest expenses under loan and guarantee, related party	160	207
Ingleside [Member]
Interest expenses under loan and guarantee, related party	$ 47	$ 0

8. Related Party Transactions47

8. Related Party Transactions (Details Narrative) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Prepaid related party operating expenses	$ 5,825	$ 5,608
Accounts payable, related party	1,126	974
Jonathan Carroll [Member]
Prepaid related party operating expenses	610	439
Ingleside [Member]
Prepaid related party operating expenses	1,215	1,169
LEH [Member]
Prepaid related party operating expenses	$ 4,000	$ 4,000

9. Accrued Expenses and Other48

9. Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Disclosure Text Block Supplement [Abstract]
Unearned revenue	$ 942	$ 450
Board of director fees payable	239	207
Other payable	145	116
Customer deposits	109	109
Insurance	89	68
Excise and income taxes payable	83	79
Property taxes	72	131
Accrued Expenses and Other Current Liabilities, Net	$ 1,679	$ 1,160

10. Long-Term Debt, Net (Detail

10. Long-Term Debt, Net (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Principal balance outstanding	$ 37,520	$ 37,679
Less: Current portion of long-term debt, net	(35,387)	(35,544)
Less: Unamortized debt issue costs	(2,102)	(2,135)
Long term debt	31	0
First Term Loan Due 2034 [Member]
Principal balance outstanding	23,020	23,199
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,450	9,502
Notre Dame Debt [Member]
Principal balance outstanding	4,978	4,978
Capital Leases [Member]
Principal balance outstanding	$ 72	$ 0

10. Long-Term Debt, Net (Deta50

10. Long-Term Debt, Net (Details 1) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 1,674	$ 1,674
Second Term Loan Due 2034	768	768
Less: Accumulated amortization	(340)	(307)
Long term debt	$ 2,102	$ 2,135

10 Long-Term Debt, Net (Details

10 Long-Term Debt, Net (Details 2) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Long-term Debt Net Details 2
Notre Dame Debt	$ 2,245	$ 2,046
LEH Loan Agreement (related party)	1,052	892
Second Term Loan Due 2034	51	49
First Term Loan Due 2034	41	40
Total	3,389	3,027
Less: Interest payable, current portion	(3,389)	(3,027)
Long term debt	$ 0	$ 0

10. Long-Term Debt, Net (Deta52

10. Long-Term Debt, Net (Details 3) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Crane	$ 94	$ 0
Less: accumulated depreciation	(3)	0
Capital lease obligation	$ 91	$ 0

10.Long-Term Debt, Net (Details

10.Long-Term Debt, Net (Details Narrative) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Amortization expense	$ 30	$ 30

11. Asset Retirement Obligati54

11. Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period	$ 2,315	$ 2,028	$ 2,028
Accretion expense	66	$ 72	287
Asset retirement obligations	2,381		2,315
Less: asset retirement obligations, current portion	(2,381)		(2,315)
Long-term asset retirement obligations, at the end of the period	$ 0		$ 0

12. Treasury Stock (Details Nar

12. Treasury Stock (Details Narrative) - shares	Mar. 31, 2018	Dec. 31, 2017
Equity [Abstract]
Treasury stock	0	150,000

13. Concentration of Risk (Deta

13. Concentration of Risk (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Total refined petroleum product sales	$ 71,512	$ 51,902
Concentration Risk	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 3	$ 120
Concentration Risk	0.00%	0.20%
Naphtha
Total refined petroleum product sales	$ 16,318	$ 13,763
Concentration Risk	22.80%	26.50%
Jet Fuel
Total refined petroleum product sales	$ 20,567	$ 15,400
Concentration Risk	28.80%	29.70%
HOBM
Total refined petroleum product sales	$ 16,429	$ 10,686
Concentration Risk	23.00%	20.60%
AGO
Total refined petroleum product sales	$ 18,195	$ 11,933
Concentration Risk	25.40%	23.00%

13. Concentration of Risk (De57

13. Concentration of Risk (Details Narrative) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Concentration Risk	100.00%	100.00%
LEH [Member]
Concentration Risk	28.80%	36.20%
Concentration risk accounts receivable	$ 300	$ 0

14. Leases (Details Narrative)

14. Leases (Details Narrative) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Leases, Operating [Abstract]
Rent expense	$ 50	$ 30

15. Income Taxes (Details)

15. Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Taxes Details
Current	$ (217)	$ 0	$ 0
Impact of change in enacted tax rates	0		(6,654)
Change in valuation allowance	109		6,654
Total provision for income taxes	$ 217		$ 0

15. Income Taxes (Details 1)

15. Income Taxes (Details 1) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 10,720	$ 9,767
Accrued arbitration award payable	3,377	4,122
Start-up costs (crude oil and condensate processing facility)	742	763
Asset retirement obligations liability/deferred revenue	507	495
AMT credit and other	109	217
Total deferred tax assets	15,455	15,365
Deferred tax liabilities:
Basis differences in property and equipment	(4,577)	(4,415)
Total deferred tax liabilities	(4,577)	(4,415)
Deferred tax assets, net	10,878	10,950
Valuation allowance	(10,769)	(10,950)
Deferred tax assets, net	$ 109	$ 0

15. Income Taxes (Details 2)

15. Income Taxes (Details 2) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Balance	$ 39,832	$ 33,176
Net operating losses	4,295	6,656
Balance at December 31	44,127	39,832
Pre-Ownership Change [Member]
Balance	9,614	9,614
Net operating losses	0	0
Balance at December 31	9,614	9,614
Post-Ownership Change [Member]
Balance	30,218	23,562
Net operating losses	4,295	6,656
Balance at December 31	$ 34,513	$ 30,218

15. Income Taxes (Details Narra

15. Income Taxes (Details Narrative) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Benefit	$ 217	$ 0

16. Earnings per share (Details

16. Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Net income (loss)	$ (151)	$ (1,850)
Basic and diluted income per share	$ (0.01)	$ (0.18)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,925,513	10,474,714