Blue Dolphin Energy (BDCO) 10-K 2 Apr 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Apr. 02, 2018	Jun. 30, 2017
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,925,513
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,017
Entity Public Float			$ 3,800,118

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 495,296	$ 1,152,628
Restricted cash	48,980	3,347,835
Accounts receivable, net	1,356,859	2,022,166
Accounts receivable, related party	652,928	1,161,589
Prepaid expenses and other current assets	1,206,971	1,046,191
Deposits	129,200	138,957
Inventory	3,089,204	2,075,538
Total current assets	6,979,438	10,944,904
Total property and equipment, net	64,596,939	62,324,463
Restricted cash, noncurrent	1,601,947	1,582,305
Surety bonds	230,000	205,000
Trade name	0	303,346
Total long-term assets	66,428,886	64,415,114
TOTAL ASSETS	73,408,324	75,360,018
CURRENT LIABILITIES
Long-term debt less unamortized debt issue costs, current portion	35,544,402	31,712,336
Long-term debt, related party, current portion	4,000,000	500,000
Interest payable, current portion	2,135,327	80,200
Interest payable, related party, current portion	892,444	243,556
Accounts payable	2,343,795	14,552,383
Accounts payable, related party	974,400	369,600
Asset retirement obligations, current portion	2,314,571	17,510
Accrued expenses and other current liabilities	1,159,465	1,281,582
Accrued arbitration award payable	27,127,863	0
Total current liabilities	76,492,267	48,757,167
Long-term liabilities:
Asset retirement obligations, net of current portion	0	2,010,129
Deferred revenues and expenses	41,695	83,390
Long-term debt less unamortized debt issue costs, net of current portion	0	1,300,000
Long-term debt, related party, net of current portion	1,608,481	4,814,690
Long-term interest payable, net of current portion	0	1,691,383
Total long-term liabilities	1,650,176	9,899,592
TOTAL LIABILITIES	78,142,443	58,656,759
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,925,513 and 10,624,714 shares issued at December 31,2017 and December 31, 2016, respectively)	109,255	106,248
Additional paid-in capital	36,906,533	36,818,528
Accumulated deficit	(41,749,907)	(19,421,517)
Treasury stock (0 and 150,000 shares at cost at December 31, 2017 and December 31, 2016, respectively)	0	(800,000)
Total stockholders' equity	(4,734,119)	16,703,259
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 73,408,324	$ 75,360,018

Consolidated Balance Sheets (Pa

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

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 255,547,311	$ 165,413,778
Tank rental revenue	2,902,268	2,366,548
Other operations	0	74,990
Total revenue from operations	258,449,579	167,855,316
COST OF OPERATIONS
Cost of refined products sold	241,104,950	161,714,526
Refinery operating expenses	8,145,553	12,040,676
Joint Marketing Agreement profit share	0	359,260
Other operating expenses	227,791	385,593
Arbitration award and associated fees	24,338,628	0
General and administrative expenses	4,021,962	2,708,594
Depletion, depreciation and amortization	1,810,134	1,935,644
Impairment expense	303,346	968,684
Bad debt expense (recovery)	81,203	(139,868)
Accretion of asset retirement obligations	287,376	112,744
Total cost of operations	280,320,943	180,085,853
Loss from operations	(21,871,364)	(12,230,537)
OTHER INCOME (EXPENSE)
Easement, interest and other income	478,638	1,924,893
Interest and other expense	(2,770,164)	(1,854,567)
Gain on disposal of property	1,834,500	0
Total other income (expense)	(457,026)	70,326
Loss before income taxes	(22,328,390)	(12,160,211)
Income tax expense	0	(3,607,237)
Net loss	$ (22,328,390)	$ (15,767,448)
Income (loss) per common share
Basic	$ (2.09)	$ (1.51)
Diluted	$ (2.09)	$ (1.51)
Weighted average number of common shares outstanding:
Basic	10,689,615	10,464,061
Diluted	10,689,615	10,464,061

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Treasury Stock	Total
Beginning Balance, shares at Dec. 31, 2015	10,603,802			(150,000)
Beginning Balance, amount at Dec. 31, 2015	$ 106,038	$ 36,738,737	$ (3,654,069)	$ (800,000)	$ 32,390,706
Common stock issued for services, shares	20,912
Common stock issued for services, amount	$ 210	79,791			80,001
Net loss			(15,767,448)		(15,767,448)
Ending Balance, shares at Dec. 31, 2016	10,624,714			(150,000)
Ending Balance, amount at Dec. 31, 2016	$ 106,248	36,818,528	(19,421,517)	$ (800,000)	16,703,259
Common stock issued for services, shares	300,799			150,000
Common stock issued for services, amount	$ 3,007	88,005		$ 800,000	891,012
Net loss			(22,328,390)		(22,328,390)
Ending Balance, shares at Dec. 31, 2017	10,925,513			0
Ending Balance, amount at Dec. 31, 2017	$ 109,255	$ 36,906,533	$ (41,749,907)	$ 0	$ (4,734,119)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES
Net income (loss)	$ (22,328,390)	$ (15,767,448)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,810,134	1,935,644
Unrealized loss (gain) on derivatives	0	(183,400)
Deferred income tax	0	3,607,237
Amortization of debt issue costs	128,484	128,485
Accretion expense	287,376	112,744
Common stock issued for services	60,000	80,001
Recovery of bad debt	81,203	(139,868)
Impairment of fixed assets	303,346	968,684
Changes in operating assets and liabilities
Accounts receivable	584,105	3,574,947
Accounts receivable, related party	508,661	(1,161,589)
Prepaid expenses and other current assets	(160,780)	95,449
Deposits and other assets	(15,243)	1,073,457
Inventory	(1,013,666)	5,732,780
Accrued arbitration award	27,127,863	0
Accounts payable, accrued expenses and other liabilities	(12,921,462)	(4,006,063)
Accounts payable, related party	604,800	69,600
Net cash provided by (used in) operating activities	(4,943,569)	(3,879,340)
INVESTING ACTIVITIES
Capital expenditures	(2,431,701)	(14,100,897)
Net cash used in investing activities	(2,431,701)	(14,100,897)
FINANCING ACTIVITIES
Proceeds from issuance of debt	3,677,953	7,118,969
Payments on debt	(1,364,031)	(3,701,616)
Net activity on related-party debt	1,124,803	0
Net cash provided by (used in) financing activities	3,438,725	3,417,353
Net decrease in cash, cash equivalents, and restricted cash	(3,936,545)	(14,562,884)
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	6,082,768	20,645,652
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	2,146,223	6,082,768
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	1,650,910	2,286,082
Financing of guaranty fees via long-term debt, related party	327,462	0
Conversion of related-party notes to common stock	831,012	0
Interest paid	2,688,449	2,357,237
Income taxes paid	$ 0	$ 0

1. Organization

1. Organization	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations Structure and Management Our operations are conducted through the following active subsidiaries: ● Lazarus Energy, LLC, a Delaware limited liability company (“LE”). ● Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”). ● Blue Dolphin Pipe Line Company, 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” for additional information regarding our operating subsidiaries, principal facilities, and assets. References in this Annual Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires. Going Concern ● Final GEL Arbitration Award – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all 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 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 April 30, 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.) If the parties are unable to reach an acceptable settlement with Genesis and GEL, and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially affected, and 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 its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations and would likely require us to seek protection under bankruptcy laws. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 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. We are currently evaluating the effects of the Final Arbitration Award on our business, financial condition, and results of operations. In addition to the matters described above, the Final Arbitration Award could materially and adversely affect our ability to procure adequate amounts of crude oil and condensate or our relationships with our customers. The contract-related dispute has negatively affected our customer relationships, prevented us from taking advantage of business opportunities, disrupted refinery operations, diverted management’s focus away from running the business, and impacted our ability to obtain financing. We can provide no assurance as to whether negotiations with GEL will result in a settlement, the potential terms of any such settlement, or whether Veritex would approve any such settlement. If LE is unable to reach an acceptable settlement with GEL or Veritex does not approve any such settlement and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and LE would likely be required to seek protection under bankruptcy laws. Operating Risks ● Net Losses – For the year ended December 31, 2017, we reported a net loss of $22,328,390, or a loss of $2.09 per share, compared to a net loss of $15,767,448, or a loss of $1.51 per share, for the year ended December 31, 2016. The $0.58 per share increase in net loss between the periods was the result of the Final Arbitration Award, which was partially offset by improved margins for refined petroleum products and increased sales volume. The amount expensed in the period related to the Final Arbitration Award was $24,338,628, which represented $2.28 per share. Excluding the Final Arbitration Award, we would have reported net income of $0.19 per share. ● Working Capital Deficits – We had a working capital deficit of $69,512,829 at December 31, 2017 compared to a working capital deficit of $37,812,263 at December 31, 2016. Excluding long-term debt, we had a working capital deficit of $29,968,427 at December 31, 2017, compared to working capital of $5,599,927 at December 31, 2016. The significant increase in working capital deficit between the periods primarily related to the Final Arbitration Award and a decrease in cash and cash equivalents. ● Crude Supply Issues – We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by the contract-related dispute with GEL and other factors, as noted above. The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts of crude oil and condensate from our current supplier or otherwise. ● Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at December 31, 2017, LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 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 the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to any proposed settlement with GEL or provide future waivers of any financial covenant defaults, which may have an adverse impact on our financial position and results of operations. During the year ended December 31, 2017, we continued aggressive actions to improve operations and liquidity. We began selling certain of our refined petroleum products immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure. We completed construction on several new petroleum storage tanks at the Nixon Facility. Increased petroleum storage capacity: (i) assists with de-bottlenecking the facility, (ii) supports increased refinery throughput up to approximately 30,000 bpd, and (iii) provides an opportunity to generate additional tank rental revenue by leasing to third-parties. We also reduced our working capital requirements in a rising cost environment by decreasing costs, reducing inventory levels, improving our sales cycle, and requiring pre-payments from certain customers. Management believes that it is taking 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, LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. Among other factors, the Final Arbitration Award could prevent us from successfully executing our business plan. For additional disclosures related to the contract-related dispute with GEL, the Final Arbitration Award, the GEL Letter Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Annual Report: ● 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: - GEL Contract-Related Dispute and Final Arbitration Award - Results of Operations - Liquidity and Capital Resources ● Part II, Item 8. Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements: - Note (8) Related Party Transactions - Note (10) Long-Term Debt, Net - Note (19) Commitments and Contingencies – Legal Matters - Note (20) Subsequent Events

2. Basis of Presentation

2. Basis of Presentation	12 Months Ended
	Dec. 31, 2017
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, 2017
Accounting Policies [Abstract]
Significant Accounting Policies	The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management who is responsible for their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements. Use of Estimates 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 year ended December 31, 2016. 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 Refined Petroleum Products Revenue Tank Rental Revenue Easement Revenue Pipeline Transportation Revenue 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 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 full valuation allowance against the deferred tax assets as of December 31, 2017. 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, 2017 and 2016, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.) Impairment or Disposal of Long-Lived Assets Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (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 (17) Earnings Per Share” for additional information related to EPS.) Treasury Stock New Pronouncements Adopted ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory New Pronouncements Issued, Not Yet Effective ASU 2018-05, Income Taxes (Topic 740) For public business entities, t ASU 2016-02, Leases (Topic 842) ASU 2014-09, Revenue from Contracts with Customers , evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update) Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers Income Statement – Reporting Comprehensive Income (Topic 220), Revenue Recognition (Topic 605), and Revenue from Contracts with Customers (Topic 606) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity. Reclassification

4. Business Segment Information

4. Business Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business Segment Information	Effective January 1, 2017, we began reporting as a single business segment – Refinery Operations. Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility. Due to their small size, current and prior year ended amounts associated with Pipeline Transportation operations were reclassified to Corporate and Other. Pipeline Transportation operations diminished significantly as services to third-parties ceased and third-party wells along our pipeline corridor were permanently abandoned. Business segment information for the periods indicated (and as of the dates indicated), was as follows: Years Ended December 31, 2017 2016 Segment Segment Refinery Refinery Operations Corporate & Other Total Operations Corporate & Other Total Revenue from operations $ 258,449,579 $ - $ 258,449,579 $ 167,780,326 $ 74,990 $ 167,855,316 Less: cost of operations(1) (252,099,846 ) (1,768,989 ) (253,868,835 ) (175,340,816 ) (2,450,133 ) (177,790,949 ) Other non-interest income(2) - 1,912,905 1,912,905 - 1,914,607 1,914,607 Less: JMA Profit Share(3) - - - (359,260 ) - (359,260 ) Less: Arbitration award(4) (24,338,628 ) - (24,338,628 ) - - - EBITDA(5) $ (17,988,895 ) $ 143,916 $ (7,919,750 ) $ (460,536 ) Depletion, depreciation and amortization (1,810,134 ) (1,935,644 ) Interest expense, net (2,673,277 ) (1,844,281 ) Loss before income taxes (22,328,390 ) (12,160,211 ) Income tax expense - (3,607,237 ) Net loss $ (22,328,390 ) $ (15,767,448 ) Capital expenditures $ 4,082,611 $ - $ 4,082,611 $ 15,041,074 $ - $ 15,041,074 Identifiable assets $ 71,708,714 $ 1,699,610 $ 73,408,324 $ 74,236,629 $ 1,123,389 $ 75,360,018 (1) Operation cost within the Refinery Operations segment includes related general and administrative expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs (such as accounting fees, director fees, and legal expense), as well as expenses associated with our pipeline assets and oil and/or gas leasehold interests (such as accretion and impairment expenses). (2) Other non-interest income reflects FLNG easement revenue. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement, under which marketing activities have ceased. (See “Note (1) Organization – Going Concern – Final GEL Arbitration Award” for further discussion related to the contract-related dispute with GEL.) (4) Arbitration award reflects damages and GEL’s attorneys’ fees and related expenses awarded to GEL as part of the Final Arbitration Award. (5) 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	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets as of the dates indicated consisted of the following: December 31, 2017 2016 Prepaid crude oil and condensate $ 912,702 $ - Prepaid insurance 294,269 248,853 Short-term tax bond - 505,000 Prepaid exise taxes - 292,338 $ 1,206,971 $ 1,046,191

6. Inventory

6. Inventory	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: December 31, 2017 2016 HOBM $ 1,558,066 $ 212,987 Crude oil and condensate 961,571 26,123 AGO 213,402 143,362 Naphtha 169,591 533,580 Chemicals 161,563 182,751 Propane 17,450 11,318 LPG mix 7,561 1,293 Jet fuel - 964,124 $ 3,089,204 $ 2,075,538

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, as of the dates indicated consisted of the following: December 31, 2017 2016 Refinery and facilities $ 51,432,434 $ 50,814,309 Land 566,159 602,938 Other property and equipment 652,795 652,795 52,651,388 52,070,042 Less: Accumulated depletion, depreciation, and amortization (8,495,378 ) (6,685,244 ) 44,156,010 45,384,798 Construction in progress 20,440,929 16,939,665 $ 64,596,939 $ 62,324,463 We capitalize interest cost incurred on funds used to construct property, plant, and equipment. The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $3,857,082 and $2,108,298 at December 31, 2017 and 2016, respectively. (8) Related Party Transactions

8. Related Party Transactions

8. Related Party Transactions	12 Months Ended
	Dec. 31, 2017
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 Tolling Agreement Financial Agreements . Loan and Security Agreement The proceeds of the LEH Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the LEH Loan Agreement. The LEH Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the LEH Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the LEH Loan Agreement is reflected in interest payable, current portion in our consolidated balance sheets. Promissory Notes ● June LEH Note ● March Ingleside Note ● March Carroll Note Outstanding principal and accrued interest owed to Ingleside and Jonathan Carroll under the March Ingleside Note and March Carroll Note, respectively, are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets. Debt Assumption Agreement Amended and Restated Guaranty Fee Agreements The First Amendment, Second Amendment, Third Amendment and Fourth Amendment prohibit 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.) (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 LEH Loan Agreement, March Ingleside Note, and March Carroll Note as of the dates indicated was as follows: December 31, 2017 2016 LEH $ 4,000,000 $ 4,000,000 Ingleside 1,168,748 722,278 Jonathan Carroll 439,733 592,412 5,608,481 5,314,690 Less: Long-term debt, related party, current portion (4,000,000 ) (500,000 ) $ 1,608,481 $ 4,814,690 Accrued interest associated with the LEH Loan Agreement was $892,444 and $243,556 at December 31, 2017 and 2016, respectively. Consolidated Statements of Operations Years Ended December 31, 2017 2016 Jet fuel sales $ 81,094,419 $ 37,757,612 Jet fuel storage fees HOBM sales 3,425,455 3,322,770 Other product sales - 2,824,408 $ 85,194,874 $ 45,029,790 Related party cost of goods sold associated with the Tolling Agreement with LMT totaled $604,800 and $369,600 for the years ended December 31, 2017 and 2016, respectively. Related party refinery operating expenses associated with the Amended and Restated Operating Agreement with LEH and the Amended and Restated Tank Lease Agreement with Ingleside for the periods indicated were as follows: Years Ended December 31, 2017 2016 Amount Per bbl Amount Per bbl LEH $ 8,145,553 $ 1.81 $ 11,140,676 $ 3.10 Ingleside - - 900,000 0.25 $ 8,145,553 $ 1.81 $ 12,040,676 $ 3.35 For the year ended December 31, 2017, refinery operating expenses per bbl decreased compared to the year ended December 31, 2016 due to the revised cost-plus expense reimbursement structure. In addition, refinery operating expenses per bbl were higher during the year ended December 31, 2016 due to significant refinery downtime. Related party interest expense associated with the LEH Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows: Years Ended December 31, 2017 2016 Jonathan Carroll $ 663,130 $ 692,969 LEH $ 706,146 243,556 $ 1,369,276 $ 936,525

9. Accrued Expenses and Other C

9. Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Unearned revenue $ 449,800 $ 408,770 Board of director fees payable 206,429 136,429 Property taxes 130,736 4,694 Other payable 116,361 189,719 Customer deposits 109,029 450,000 Excise and income taxes payable 79,260 24,187 Insurance 67,850 67,783 $ 1,159,465 $ 1,281,582

10. Long-Term Debt, Net

10. Long-Term Debt, Net	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt, Net	Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following: December 31, 2017 2016 First Term Loan Due 2034 (in default) $ 23,199,031 $ 23,924,607 Second Term Loan Due 2034 (in default) 9,501,930 9,729,853 Notre Dame Debt (in default) 4,977,953 1,300,000 Term Loan Due 2017 - 184,994 Capital Leases - 135,879 $ 37,678,914 $ 35,275,333 Less: Current portion of long-term debt, net (35,544,402 ) (31,712,336 ) Less: Unamortized debt issue costs (2,134,512 ) (2,262,997 ) $ - $ 1,300,000 Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following: December 31, 2017 2016 First Term Loan Due 2034 (in default) $ 1,673,545 $ 1,673,545 Second Term Loan Due 2034 (in default) 767,673 767,673 Less: Accumulated amortization (306,706 ) (178,221 ) $ 2,134,512 $ 2,262,997 Amortization expense was $128,484 and $128,233 for the years ended December 31, 2017 and 2016, respectively. Accrued interest associated with long-term debt, net is reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets and includes related party interest. Accrued interest as of the dates indicated consisted of the following: December 31, 2017 2016 Notre Dame Debt (in default) $ 2,046,083 $ 1,691,383 LEH Loan Agreement (related party) 892,444 243,556 Second Term Loan Due 2034 (in default) 49,202 44,984 First Term Loan Due 2034 (in default) 40,042 33,866 Capital Leases - 1,165 Term Loan Due 2017 - 185 3,027,771 2,015,139 Less: Interest payable, current portion (3,027,771 ) (323,756 ) Long-term interest payable, net of current portion $ - $ 1,691,383 At December 31, 2017, our expected future long-term debt payments were as follow: Years Ending December 31, Principal Debt Issue Costs Total 2018 $ 41,678,914 $ (2,134,512 ) $ 39,544,402 2019 1,608,481 - 1,608,481 2020 - - - 2021 - - - 2022 - - - Subsequent to 2022 - - - $ 43,287,395 $ (2,134,512 ) $ 41,152,883 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 December 31, 2017, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 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 us to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee 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) Consolidated Financial Statements (Continued) 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 us to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he 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. For the years ended December 31, 2017 and 2016, guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $192,108 and $197,024, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. (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.) LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the Nixon Facility and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Notre Dame Debt (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 Nixon Facility and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Term Loan Due 2017 As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee r epayment Capital Leases A summary of equipment held under long-term capital leases as of the dates indicated follows: December 31, 2017 2016 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation 7,655 - $ 546,253 $ 538,598 At December 31, 2017, there were no future minimum lease commitments under non-cancelable capital leases.

11. Asset Retirement Obligation

11. Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Asset retirement obligations, at the beginning of the period $ 2,027,639 $ 1,985,864 Liabilities settled (444 ) (70,969 ) Accretion expense 287,376 112,744 2,314,571 2,027,639 Less: asset retirement obligations, current portion (2,314,571 ) (17,510 ) Long-term asset retirement obligations, at the end of the period $ - $ 2,010,129 Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability. At December 31, 2017 and 2016, we recognized $444 and $70,969, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability. For the years ended December 31, 2017 and 2016, we recognized $0 in abandonment expense.

12. Impairment

12. Impairment	12 Months Ended
	Dec. 31, 2017
Impairment
Impairment	For the years ended December 31, 2017 and 2016, we recorded impairment expense of $303,346 and $968,684, respectively. The impairment expense for the year ended December 31, 2017 related to trade name. The impairment expense for the year ended December 31, 2016 related to our pipeline fixed assets. 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.

13. Treasury Stock

13. Treasury Stock	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Treasury Stock	At December 31, 2017 and 2016, we had 0 and 150,000 shares of treasury stock, respectively. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates.

14. Concentration of Risk

14. Concentration of Risk	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier As discussed elsewhere in this Annual Report, we ceased purchases of crude oil and condensate from GEL under the Crude Supply Agreement in November 2016. (See “Part I, Item 1A. Risk Factors” and “Note (19) Commitments and Contingencies – Legal Matters” for disclosures related to the Crude Supply Agreement, the contract-related dispute with GEL, and the Final Arbitration Award.) We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements. The Final Arbitration Award could have a material adverse effect on our ability to procure adequate amounts of crude oil and condensate from our current supplier or otherwise. Significant Customers For the year 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 million in accounts receivable. LEH, which is HUBZone certified, purchases our jet fuel and resells the jet fuel to a government agency. (See “Part I, Item 1. Business – Management” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (8) Related Party Transactions, Note (10) Long-Term Debt, Net, and Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.) For the year ended December 31, 2016, we had 4 customers that accounted for approximately 67% of our refined petroleum product sales. LEH was one of these 4 significant customers and accounted for approximately 27% of our refined petroleum product sales. At December 31, 2016, these 4 customers represented approximately $1.6 million in accounts receivable. LEH represented approximately $1.6 million in accounts receivable. Refined Petroleum Product Sales Years Ended December 31, 2017 2016 LPG mix $ 122,911 0.1 % $ 714,285 0.4 % Naphtha 60,407,725 23.6 % 35,544,394 21.5 % Jet fuel 81,094,418 31.7 % 55,459,227 33.5 % HOBM 54,851,030 21.5 % 35,924,098 21.8 % Reduced Crude - 0.0 % 3,791,919 2.3 % AGO 59,071,227 23.1 % 33,979,855 20.5 % $ 255,547,311 100.0 % $ 165,413,778 100.0 %

15. Leases

15. Leases	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Leases	Our principal office is in Houston, Texas. The office space is leased by BDSC, as lessee, under a 2006 lease agreement that expired in September 2017. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that: (i) reduced the leased premises from 13,878 square feet to 7,675 square feet (ii) extended the lease period by sixty-eight (68) months expiring on August 31, 2023, and (iii) has an initial monthly base rental of $18,868. Of the 7,675 square feet, 1,186 square feet is used and paid for by LEH. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For the years ended December 31, 2017 and 2016, rent expense totaled $161,920 and $142,604, respectively. Rent expense is recognized on a straight-line basis. At December 31, 2017, there were no future minimum lease commitments that were non-cancelable under our expiring office lease. However, future minimum lease commitments that were non-cancelable under the Lease Amendment were as follow: Years Ending December 31, 2018 $ 113,206 2019 190,276 2020 229,930 2021 233,448 2022 237,285 2023 160,535 $ 1,164,680

16. Income Taxes

16. Income Taxes	12 Months Ended
	Dec. 31, 2017
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 year ended December 31, 2017. The provision for income taxes as of the dates indicated consisted of the following: December 31, 2017 2016 Current $ - $ - Deferred - Deferred provision - Impact of change in enacted tax rates 6,654,184 - Change in valuation allowance (6,654,184 ) (3,607,237 ) Total provision for income taxes $ - $ (3,607,237 ) 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 reduced our net deferred tax assets by $6,654,184. In 2016, our effective tax rate differed from the U.S. federal statutory rate primarily due to a change in the valuation allowance of our deferred tax assets. The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross profit rather than on its net income, certain aspects of TMT make it like an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. Effective Tax Rate December 31, 2017 2016 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 0.00 % 0.00 % Federal tax 0.00 % 0.00 % Change in valuation allowance (34.00 %) (63.66 %) 0.00 % (29.66 %) Deferred income taxes as of the dates indicated consisted of the following: December 31, 2017 2016 Deferred tax assets: Net operating loss and capital loss carryforwards $ 9,767,205 $ 13,550,338 Accrued arbitration award payable 4,122,187 - Start-up costs (Nixon Facility) 763,428 1,373,363 Asset retirement obligations liability/deferred revenue 494,816 717,751 AMT credit and other 216,925 266,522 Total deferred tax assets 15,364,561 15,907,974 Deferred tax liabilities: Basis differences in property and equipment (4,415,061 ) (5,895,943 ) Total deferred tax liabilities (4,415,061 ) (5,895,943 ) 10,949,500 10,012,031 Valuation allowance (10,949,500 ) (10,012,031 ) Deferred tax assets, net $ - $ - 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 Balance at December 31, 2015 $ 9,614,449 $ 9,616,941 $ 19,231,390 Net operating losses - 13,945,128 13,945,128 Balance at December 31, 2016 $ 9,614,449 $ 23,562,069 $ 33,176,518 Net operating losses - 6,656,563 6,656,563 Balance at December 31, 2017 $ 9,614,449 $ 30,218,632 $ 39,833,081 Valuation Allowance

17. Earnings Per Share

17. Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Years Ended December 31, 2017 2016 Net loss $ (22,328,390 ) $ (15,767,448 ) Basic and diluted income per share $ (2.09 ) $ (1.51 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,689,615 10,464,061 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 years ended December 31, 2017 and 2016 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

18. Inventory Risk Management

18. Inventory Risk Management	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Inventory Risk Management	During 2017, we began selling certain of our refined petroleum products immediately following production, which minimizes inventory, improves cash flow, and reduces commodity risk/exposure. Previously, Genesis/GEL used commodity futures contracts to mitigate the volatile change in value for our crude oil and refined petroleum products inventory. The following table provides the effect of derivative instruments in our consolidated statements of operations for the years ended December 31, 2017 and 2016: Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2017 2016 Commodity contracts Cost of refined products sold $ - $ (2,445,898 )

19. Commitments and Contingenci

19. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Matters GEL Contract-Related Dispute and Final Arbitration Award Veritex Secured Loan Agreement Event of Default Other Legal Matters Amended and Restated Operating Agreement Financing Agreements Guarantees Health, Safety and Environmental Matters Nixon Facility Expansion Supplemental Pipeline Bonds

20. Subsequent Events

20. Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	BDSC Principal Office Lease Sixth Amendment to GEL Letter Agreement

3. Significant Accounting Pol27

3. Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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. Cash and cash equivalents totaled $495,296 and $1,152,628 at December 31, 2017 and 2016, respectively.
Restricted Cash	Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks. At December 31, 2017, total restricted cash was $1,650,927, comprised of restricted cash (current portion) totaling $48,980 and restricted cash, noncurrent totaling $1,601,947. At December 31, 2016, total restricted cash was $4,930,140, comprised of restricted cash (current portion) totaling $3,347,835 and restricted cash, noncurrent totaling $1,582,305
Accounts Receivable, 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 December 31, 2017 and 2016.
Inventory	Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See “Note (6) Inventory” for additional disclosures related to our inventory.)
Property and Equipment	Refinery and Facilities 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 year ended December 31, 2016. 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	Refined Petroleum Products Revenue Tank Rental Revenue Easement Revenue Pipeline Transportation Revenue 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 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 full valuation allowance against the deferred tax assets as of December 31, 2017. 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, 2017 and 2016, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.)
Impairment or Disposal of Long-Lived Assets	In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 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 year ended December 31, 2016.
Asset Retirement Obligations	FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (11) Asset Retirement Obligations” for additional information related to our AROs.)
Computation of Earnings Per Share	We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of operations and requires a reconciliation of the denominator of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) 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 (13) 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 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory
New Pronouncements Issued, Not Yet Effective	The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows: ASU 2018-05, Income Taxes (Topic 740) For public business entities, t ASU 2016-02, Leases (Topic 842) ASU 2014-09, Revenue from Contracts with Customers , evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net) Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update) Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers Income Statement – Reporting Comprehensive Income (Topic 220), Revenue Recognition (Topic 605), and Revenue from Contracts with Customers (Topic 606) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.
Reclassification	Effective January 1, 2017, we reclassified amounts associated with our Pipeline Transportation operations to Corporate and Other. (See “Note (4) Business Segment Information” for disclosures related to Corporate and Other.)

4. Business Segment Informati28

4. Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Business segment reporting	Years Ended December 31, 2017 2016 Segment Segment Refinery Refinery Operations Corporate & Other Total Operations Corporate & Other Total Revenue from operations $ 258,449,579 $ - $ 258,449,579 $ 167,780,326 $ 74,990 $ 167,855,316 Less: cost of operations(1) (252,099,846 ) (1,768,989 ) (253,868,835 ) (175,340,816 ) (2,450,133 ) (177,790,949 ) Other non-interest income(2) - 1,912,905 1,912,905 - 1,914,607 1,914,607 Less: JMA Profit Share(3) - - - (359,260 ) - (359,260 ) Less: Arbitration award(4) (24,338,628 ) - (24,338,628 ) - - - EBITDA(5) $ (17,988,895 ) $ 143,916 $ (7,919,750 ) $ (460,536 ) Depletion, depreciation and amortization (1,810,134 ) (1,935,644 ) Interest expense, net (2,673,277 ) (1,844,281 ) Loss before income taxes (22,328,390 ) (12,160,211 ) Income tax expense - (3,607,237 ) Net loss $ (22,328,390 ) $ (15,767,448 ) Capital expenditures $ 4,082,611 $ - $ 4,082,611 $ 15,041,074 $ - $ 15,041,074 Identifiable assets $ 71,708,714 $ 1,699,610 $ 73,408,324 $ 74,236,629 $ 1,123,389 $ 75,360,018

5. Prepaid Expenses and Other29

5. Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Liabilities extinguished
Prepaid expenses and other current assets	December 31, 2017 2016 Prepaid crude oil and condensate $ 912,702 $ - Prepaid insurance 294,269 248,853 Short-term tax bond - 505,000 Prepaid exise taxes - 292,338 $ 1,206,971 $ 1,046,191

6. Inventory (Tables)

6. Inventory (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventory	December 31, 2017 2016 HOBM $ 1,558,066 $ 212,987 Crude oil and condensate 961,571 26,123 AGO 213,402 143,362 Naphtha 169,591 533,580 Chemicals 161,563 182,751 Propane 17,450 11,318 LPG mix 7,561 1,293 Jet fuel - 964,124 $ 3,089,204 $ 2,075,538

7. Property, Plant and Equipm31

7. Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property and equipment	December 31, 2017 2016 Refinery and facilities $ 51,432,434 $ 50,814,309 Land 566,159 602,938 Other property and equipment 652,795 652,795 52,651,388 52,070,042 Less: Accumulated depletion, depreciation, and amortization (8,495,378 ) (6,685,244 ) 44,156,010 45,384,798 Construction in progress 20,440,929 16,939,665 $ 64,596,939 $ 62,324,463

8. Related Party Transactions (

8. Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Accounts Payable, Related Party	December 31, 2017 2016 LEH $ 4,000,000 $ 4,000,000 Ingleside 1,168,748 722,278 Jonathan Carroll 439,733 592,412 5,608,481 5,314,690 Less: Long-term debt, related party, current portion (4,000,000 ) (500,000 ) $ 1,608,481 $ 4,814,690
Accrued interest Expenses	Years Ended December 31, 2017 2016 Jet fuel sales $ 81,094,419 $ 37,757,612 Jet fuel storage fees HOBM sales 3,425,455 3,322,770 Other product sales - 2,824,408 $ 85,194,874 $ 45,029,790
Refinery operating expenses	Years Ended December 31 2017 2016 Amount Per bbl Amount Per bbl LEH $ 8,145,553 $ 1.81 $ 11,140,676 $ 3.10 Ingleside - - 900,000 0.25 $ 8,145,553 $ 1.81 $ 12,040,676 $ 3.35 Related party interest expense associated with the LEH Loan Agreement and Amended and Restated Guaranty Fee Agreements for the periods indicated was as follows: Years Ended December 31, 2017 2016 Jonathan Carroll $ 663,130 $ 692,969 LEH $ 706,146 243,556 $ 1,369,276 $ 936,525

9. Accrued Expenses and Other33

9. Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Accrued Expenses And Other Current Liabilities Tables
Accrued expenses and other current liabilities	December 31, 2017 2016 Unearned revenue $ 449,800 $ 408,770 Board of director fees payable 206,429 136,429 Property taxes 130,736 4,694 Other payable 116,361 189,719 Customer deposits 109,029 450,000 Excise and income taxes payable 79,260 24,187 Insurance 67,850 67,783 $ 1,159,465 $ 1,281,582

10. Long-Term Debt, Net (Tables

10. Long-Term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long Term Debt	December 31, 2017 2016 First Term Loan Due 2034 (in default) $ 23,199,031 $ 23,924,607 Second Term Loan Due 2034 (in default) 9,501,930 9,729,853 Notre Dame Debt (in default) 4,977,953 1,300,000 Term Loan Due 2017 - 184,994 Capital Leases - 135,879 $ 37,678,914 $ 35,275,333 Less: Current portion of long-term debt, net (35,544,402 ) (31,712,336 ) Less: Unamortized debt issue costs (2,134,512 ) (2,262,997 ) $ - $ 1,300,000
Debt issue costs	December 31, 2017 2016 First Term Loan Due 2034 (in default) $ 1,673,545 $ 1,673,545 Second Term Loan Due 2034 (in default) 767,673 767,673 Less: Accumulated amortization (306,706 ) (178,221 ) $ 2,134,512 $ 2,262,997
Accrued interest related to our long-term debt, net	December 31, 2017 2016 Notre Dame Debt (in default) $ 2,046,083 $ 1,691,383 LEH Loan Agreement (related party) 892,444 243,556 Second Term Loan Due 2034 (in default) 49,202 44,984 First Term Loan Due 2034 (in default) 40,042 33,866 Capital Leases - 1,165 Term Loan Due 2017 - 185 3,027,771 2,015,139 Less: Interest payable, current portion (3,027,771 ) (323,756 ) Long-term interest payable, net of current portion $ - $ 1,691,383
Schedule of summary of equipment held under long-term capital leases	Principal Debt Issue Costs Total 2018 $ 41,678,914 $ (2,134,512 ) $ 39,544,402 2019 1,608,481 - 1,608,481 2020 - - - 2021 - - - 2022 - - - Subsequent to 2022 - - - $ 43,287,395 $ (2,134,512 ) $ 41,152,883
Summary of equipment held under long-term capital leases	December 31, 2017 2016 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation 7,655 - $ 546,253 $ 538,598

11. Asset Retirement Obligati35

11. Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	December 31, 2017 2016 Asset retirement obligations, at the beginning of the period $ 2,027,639 $ 1,985,864 Liabilities settled (444 ) (70,969 ) Accretion expense 287,376 112,744 2,314,571 2,027,639 Less: asset retirement obligations, current portion (2,314,571 ) (17,510 ) Long-term asset retirement obligations, at the end of the period $ - $ 2,010,129

14. Concentration of Risk (Tabl

14. Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2017
Concentration Of Risk Tables
Percentages of all refined petroleum products sales to total sales	Years Ended December 31, 2017 2016 LPG mix $ 122,911 0.1 % $ 714,285 0.4 % Naphtha 60,407,725 23.6 % 35,544,394 21.5 % Jet fuel 81,094,418 31.7 % 55,459,227 33.5 % HOBM 54,851,030 21.5 % 35,924,098 21.8 % Reduced Crude - 0.0 % 3,791,919 2.3 % AGO 59,071,227 23.1 % 33,979,855 20.5 % $ 255,547,311 100.0 % $ 165,413,778 100.0 %

15. Leases (Tables)

15. Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Future minimum lease payments	Years Ending December 31, 2018 $ 113,206 2019 190,276 2020 229,930 2021 233,448 2022 237,285 2023 160,535 $ 1,164,680

16. Income Taxes (Tables)

16. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	December 31, 2017 2016 Current $ - $ - Deferred - Deferred provision - Impact of change in enacted tax rates 6,654,184 - Change in valuation allowance (6,654,184 ) (3,607,237 ) Total provision for income taxes $ - $ (3,607,237 )
Effective tax rate	December 31, 2017 2016 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 0.00 % 0.00 % Federal tax 0.00 % 0.00 % Change in valuation allowance (34.00 %) (63.66 %) 0.00 % (29.66 %)
Deferred tax assets and deferred tax liabilities	December 31, 2017 2016 Deferred tax assets: Net operating loss and capital loss carryforwards $ 9,767,205 $ 13,550,338 Accrued arbitration award payable 4,122,187 - Start-up costs (Nixon Facility) 763,428 1,373,363 Asset retirement obligations liability/deferred revenue 494,816 717,751 AMT credit and other 216,925 266,522 Total deferred tax assets 15,364,561 15,907,974 Deferred tax liabilities: Basis differences in property and equipment (4,415,061 ) (5,895,943 ) Total deferred tax liabilities (4,415,061 ) (5,895,943 ) 10,949,500 10,012,031 Valuation allowance (10,949,500 ) (10,012,031 ) Deferred tax assets, net $ - $ -
NOL carryforwards	Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total Balance at December 31, 2015 $ 9,614,449 $ 9,616,941 $ 19,231,390 Net operating losses - 13,945,128 13,945,128 Balance at December 31, 2016 $ 9,614,449 $ 23,562,069 $ 33,176,518 Net operating losses - 6,656,563 6,656,563 Balance at December 31, 2017 $ 9,614,449 $ 30,218,632 $ 39,833,081

17. Earnings Per Share (Tables)

17. Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings per share	Years Ended December 31, 2017 2016 Net loss $ (22,328,390 ) $ (15,767,448 ) Basic and diluted income per share $ (2.09 ) $ (1.51 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,689,615 10,464,061

18. Inventory Risk Management (

18. Inventory Risk Management (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Effect of derivative instruments	Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2017 2016 Commodity contracts Cost of refined products sold $ - $ (2,445,898 )

3. Significant Accounting Pol41

3. Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 495,296	$ 1,152,628
Restricted cash	48,980	3,347,835
Restricted cash, noncurrent	1,601,947	1,582,305
Allowance for doubtful accounts	0	0
Impairment expense	303,346	968,684
Trade name	$ 0	$ 303,346

4. Business Segment Informati42

4. Business Segment Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Revenue from operations	$ 258,449,579	$ 167,855,316
Less: cost of operations	(253,868,835)	(177,790,949)
Other non-interest income	1,912,905	1,914,607
Adjusted EBITDA	0	(359,260)
Less: JMA Profit Share	(24,338,628)	0
Depletion, depreciation and amortization	(1,810,134)	(1,935,644)
Interest expense, net	(2,673,277)	(1,844,281)
Loss before income taxes	(22,328,390)	(12,160,211)
Income tax expense	0	(3,607,237)
Net loss	(22,328,390)	(15,767,448)
Capital expenditures	4,082,611	15,041,074
Identifiable assets	73,408,324	75,360,018
Segment Refinery Operations [Member]
Revenue from operations	258,449,579	167,780,326
Less: cost of operations	(252,099,846)	(175,340,816)
Other non-interest income	0	0
Adjusted EBITDA	0	(359,260)
Less: JMA Profit Share	(24,338,628)	0
EBITDA	(17,988,895)	(7,919,750)
Capital expenditures	4,082,611	15,041,074
Identifiable assets	71,708,714	74,236,629
Corporate and Other
Revenue from operations	0	74,990
Less: cost of operations	(1,768,989)	(2,450,133)
Other non-interest income	1,912,905	1,914,607
Adjusted EBITDA	0	0
Less: JMA Profit Share	0	0
EBITDA	143,916	(460,536)
Capital expenditures	0	0
Identifiable assets	$ 1,699,610	$ 1,123,389

5. Prepaid Expenses and Other43

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Long-Term Debt Details 1
Prepaid crude oil and condensate	$ 912,702	$ 0
Prepaid insurance	294,269	248,853
Short-term tax bond	0	505,000
Prepaid exise taxes	0	292,338
Prepaid Expenses, Net	$ 1,206,971	$ 1,046,191

6. Inventory (Details)

6. Inventory (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
HOBM	$ 1,558,066	$ 212,987
Crude oil and condensate	961,571	26,123
AGO	213,402	143,362
Naphtha	169,591	533,580
Chemicals	161,563	182,751
Propane	17,450	11,318
LPG mix	7,561	1,293
Jet fuel	0	964,124
Inventories, Net	$ 3,089,204	$ 2,075,538

7. Property, Plant and Equipm45

7. Property, Plant and Equipment, Net (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment Net Details
Refinery and facilities	$ 51,432,434	$ 50,814,309
Land	566,159	602,938
Other property and equipment	652,795	652,795
Property, Plant and Equipment, Gross	52,651,388	52,070,042
Less: Accumulated depletion, depreciation, and amortization	(8,495,378)	(6,685,244)
Property, Plant and Equipment less depreciation	44,156,010	45,384,798
Construction in Progress	20,440,929	16,939,665
Property, Plant and Equipment, Net	$ 64,596,939	$ 62,324,463

7. Property, Plant and Equipm46

7. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment Net Details Narrative
Interest Costs Capitalized	$ 3,857,082	$ 2,108,298

8. Related Party Transactions47

8. Related Party Transactions (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 30, 2016
Prepaid operating expenses, related party	$ 5,608,481	$ 5,314,690
Less: Long-term debt - current portion, related party	(35,544,402)	(31,712,336)
Long-term debt - net of current portion, related party	1,608,481	4,814,690
LEH [Member]
Prepaid operating expenses, related party	4,000,000		$ 4,000,000
Ingleside [Member]
Prepaid operating expenses, related party	1,168,748	722,278
Jonathan Carroll [Member]
Prepaid operating expenses, related party	$ 439,733	$ 592,412

8. Related Party Transactions48

8. Related Party Transactions (Details 1) - LEH [Member] - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Jet fuel sales	$ 81,094,419	$ 37,757,612
Jet fuel storag fees	3,425,455	3,322,770
HOBM sales	0	2,824,408
Total	$ 85,194,874	$ 45,029,790

8. Related Party Transactions49

8. Related Party Transactions (Details 2)	12 Months Ended
	Dec. 31, 2017USD ($)$ / Boe	Dec. 31, 2016USD ($)$ / Boe
Refinery operating expenses, Amount | $	$ 8,145,553	$ 12,040,676
Refinery operating expenses, Per bbl | $ / Boe	1.81	1.81
LEH [Member]
Refinery operating expenses, Amount | $	$ 8,145,553	$ 11,140,676
Refinery operating expenses, Per bbl | $ / Boe	1.81	1.81
Ingleside [Member]
Refinery operating expenses, Amount | $	$ 0	$ 900,000
Refinery operating expenses, Per bbl | $ / Boe	0	0

8. Related Party Transactions50

8. Related Party Transactions (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Interest expenses under loan and guarantee, related party	$ 1,369,276	$ 936,525
LEH [Member]
Interest expenses under loan and guarantee, related party	663,130	692,969
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	$ 706,146	$ 243,556

8. Related Party Transactions51

8. Related Party Transactions (Details Narrative) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable, related party	$ 652,928	$ 1,161,589

9. Accrued Expenses and Other52

9. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accrued Expenses And Other Current Liabilities Details
Unearned revenue	$ 449,800	$ 408,770
Board of director fees payable	206,429	136,429
Property taxes	130,736	4,694
Other payable	116,361	189,719
Customer deposits	109,029	450,000
Excise and income taxes payable	79,260	24,187
Insurance	67,850	67,783
Accrued Expenses and Other Current Liabilities, Net	$ 1,159,465	$ 1,281,582

10. Long-Term Debt, Net (Detail

10. Long-Term Debt, Net (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 23,199,031	$ 23,924,607
Second Term Loan Due 2034	9,501,930	9,729,853
Notre Dame Debt	4,977,953	1,300,000
Term Loan Due 2017	0	184,994
Capital Leases	0	135,879
Total	37,678,914	35,275,333
Less: current portion of long-term debt	(35,544,402)	(31,712,336)
Less: unamortized debt issue costs	(2,134,512)	(2,262,997)
Long term debt	$ 0	$ 1,300,000

10. Long-Term Debt, Net (Deta54

10. Long-Term Debt, Net (Details 1) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Debt Issue Costs	$ 2,134,512	$ 2,262,997
Less: Accumulated amortization	(306,706)	(178,221)
First Term Loan Due 2034 [Member]
Debt Issue Costs	1,673,545	1,673,545
Second Term Loan Due 2034 [Member]
Debt Issue Costs	$ 767,673	$ 767,673

10. Long-Term Debt, Net (Deta55

10. Long-Term Debt, Net (Details 2) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Interest payable	$ 3,027,771	$ 2,015,139
Less: Interest payable, current portion	(2,135,327)	(80,200)
Interest payable, noncurrent	0	1,691,383
Notre Dame Debt [Member]
Interest payable	2,046,083	1,691,383
LEH [Member]
Interest payable	892,444	243,556
Second Term Loan Due 2034 [Member]
Interest payable	49,202	44,984
First Term Loan Due 2034 [Member]
Interest payable	40,042	33,866
Capital Leases [Member]
Interest payable	0	1,165
Term Loan Due 2017 [Member]
Interest payable	$ 0	$ 185

10. Long-Term Debt, Net (Deta56

10. Long-Term Debt, Net (Details 3)	Dec. 31, 2017USD ($)
2,018	$ 39,544,402
2,019	1,608,481
2,020	0
2,021	0
2,022	0
Subsequent to 2022	0
Long Term Debt Payment, Net	41,152,883
Principal
2,018	41,678,914
2,019	1,608,481
2,020	0
2,021	0
2,022	0
Subsequent to 2022	0
Long Term Debt Payment, Net	43,287,395
Debt Issuance Costs
2,018	(2,134,512)
2,019	0
2,020	0
2,021	0
2,022	0
Subsequent to 2022	0
Long Term Debt Payment, Net	$ (2,134,512)

10. Long-Term Debt, Net (Deta57

10. Long-Term Debt, Net (Details 4) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Long-term Debt Net Details 4
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation	7,655	0
Capital lease obligation	$ 546,253	$ 538,598

10. Long-Term Debt, Net (Deta58

10. Long-Term Debt, Net (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Amortization expense	$ 128,484	$ 128,485
Principal balance outstanding	0	1,300,000
Capital Leases	0	135,879
Term Loan Due 2034 [Member]
Guaranty fees	470,610	485,463
Second Term Loan Due 2034 [Member]
Guaranty fees	192,108	197,024
Term Loan Due 2017 [Member]
Guaranty fees	$ 411	$ 10,483

11. Asset Retirement Obligati59

11. Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations Details
Asset retirement obligations, at the beginning of the period	$ 2,027,639	$ 1,985,864
Liabilities settled	(444)	(70,969)
Accretion expense	287,376	112,744
Total	2,314,571	2,027,639
Less: current portion of asset retirement obligations	(2,314,571)	(17,510)
Long-term asset retirement obligations, at the end of the period	$ 0	$ 2,010,129

11. Asset Retirement Obligati60

11. Asset Retirement Obligations (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations Details Narrative
Liabilities settled recognized	$ 444	$ 70,969
Abandonment expense	$ 0	$ 0

12. Impairment (Details Narrati

12. Impairment (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Impairment Details Narrative
Impairment expense	$ 303,346	$ 968,684

13. Treasury Stock (Details Nar

13. Treasury Stock (Details Narrative) - shares	Dec. 31, 2017	Dec. 31, 2016
Treasury Stock Details Narrative
Treasury stock	0	150,000

14. Concentration of Risk (Deta

14. Concentration of Risk (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Total refined petroleum product sales	$ 255,547,311	$ 165,413,778
Concentration Risk	100.00%	100.00%
LPG mix [Member]
Total refined petroleum product sales	$ 122,911	$ 714,285
Concentration Risk	0.10%	0.40%
Naphtha
Total refined petroleum product sales	$ 60,407,725	$ 35,544,394
Concentration Risk	23.60%	21.50%
Jet Fuel [Member]
Total refined petroleum product sales	$ 81,094,418	$ 55,459,227
Concentration Risk	31.70%	33.50%
HOBM [Member]
Total refined petroleum product sales	$ 54,851,030	$ 35,924,098
Concentration Risk	21.50%	21.80%
Reduced crude [Member]
Total refined petroleum product sales	$ 0	$ 3,791,919
Concentration Risk	0.00%	2.30%
AGO [Member]
Total refined petroleum product sales	$ 59,071,227	$ 33,979,855
Concentration Risk	23.10%	20.50%

14. Concentration of Risk (De64

14. Concentration of Risk (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250,000	$ 250,000
Excess of the FDIC insurance limit	$ 1,602,045	$ 5,372,689
Sales Revenue [Member] | Three customers [Member]
Concentration Risk	70.00%
Sales Revenue [Member] | Four customers [Member]
Concentration Risk		67.00%
Account receivable [Member] | Three customers [Member]
Accounts receivable	$ 1,300,000
Account receivable [Member] | Four customers [Member]
Accounts receivable		$ 1,600,000

15. Leases (Details)

15. Leases (Details)	Dec. 31, 2017USD ($)
Leases Details 1
2,018	$ 113,206
2,019	190,276
2,020	229,930
2,021	233,448
2,022	237,285
2,023	160,535
Leases Futurre Minimum Payment, Net	$ 1,164,680

15. Leases (Details Narrative)

15. Leases (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Leases Details Narrative
Rent expense	$ 161,920	$ 142,604

16. Income Taxes (Details)

16. Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Taxes Details
Current	$ 0	$ 3,607,237
Deferred	0	3,607,237
Deferred provision	0	0
Impact of change in enacted tax rates	6,654,184	0
Change in valuation allowance	(6,654,184)	(3,607,237)
Total provision for income taxes	$ 0	$ (3,607,237)

16. Income Taxes (Details 1)

16. Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Taxes Details Narrative Abstract
Expected tax rate	34.00%	34.00%
Permanent differences	0.00%	0.00%
State tax	0.00%	0.00%
Federal tax	0.00%	0.00%
Change in valuation allowance	(34.00%)	0.00%
Expected tax rate Continuing Operations	0.00%	34.00%

16. Income Taxes (Details 2)

16. Income Taxes (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Balance	$ 33,176,518	$ 19,231,390
Net operating losses generated post-acquisition	6,656,563	13,945,128
Balance	39,833,081	33,176,518
Pre-Ownership Change [Member]
Balance	9,614,449	9,614,449
Net operating losses generated post-acquisition	0	0
Balance	9,614,449	9,614,449
Post-Ownership Change [Member]
Balance	23,562,069	9,616,941
Net operating losses generated post-acquisition	6,656,563	13,945,128
Balance	$ 30,218,632	$ 23,562,069

16. Income Taxes (Details 3)

16. Income Taxes (Details 3) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 9,767,205	$ 13,550,338
Accrued arbitration award payable	(27,127,863)	0
Start-up costs (Nixon Facility)	763,428	1,373,363
Asset retirement obligations liability/deferred revenue	494,816	717,751
AMT credit and other	216,925	266,522
Total deferred tax assets	15,364,561	15,907,974
Deferred tax liabilities:
Basis differences in property and equipment	(4,415,061)	(5,895,943)
Total deferred tax liabilities	(4,415,061)	(5,895,943)
Deferred tax assets, net	10,949,500	10,012,031
Valuation allowance	(10,949,500)	(10,012,031)
Deferred tax assets, net	$ 0	$ 0

17. Earnings per share (Details

17. Earnings per share (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net income (loss)	$ (22,328,390)	$ (15,767,448)
Basic and diluted income (loss) per share	$ (2.09)	$ (1.51)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,689,615	10,464,061

18. Inventory Risk Management72

18. Inventory Risk Management (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Inventory Risk Management Details
Cost of refined products sold	$ 0	$ (2,445,898)