Blue Dolphin Energy (BDCO) 10-K 31 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 31, 2017	Jun. 30, 2016
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, 2016
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		10,474,714
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,016
Entity Public Float			$ 8,000,248

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 1,152,628	$ 1,853,875
Restricted cash	3,347,835	3,175,299
Accounts receivable, net	2,022,166	5,457,245
Accounts receivable, related party	1,161,589	0
Prepaid expenses and other current assets	1,046,191	939,690
Deposits	138,957	395,414
Inventory	2,075,538	7,808,318
Total current assets	10,944,904	19,629,841
Total property and equipment, net	62,324,463	48,841,812
Restricted cash, noncurrent	1,582,305	15,616,478
Surety bonds	205,000	1,022,000
Debt issue costs, net	0	0
Trade name	303,346	303,346
Deferred tax assets, net	0	3,607,237
Total long-term assets	64,415,114	69,390,873
TOTAL ASSETS	75,360,018	89,020,714
CURRENT LIABILITIES
Accounts payable	14,552,383	14,882,714
Accounts payable, related party	369,600	300,000
Asset retirement obligations, current portion	17,510	38,644
Accrued expenses and other current liabilities	1,281,582	2,990,891
Interest payable, current portion	323,756	81,467
Long-term debt less unamortized debt issue costs, current portion	31,712,336	1,934,932
Long-term debt, related party, current portion	500,000	0
Total current liabilities	48,757,167	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	2,010,129	1,947,220
Deferred revenues and expenses	83,390	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,300,000	32,846,254
Long-term debt, related party, net of current portion	4,814,690	0
Long-term interest payable, net of current portion	1,691,383	1,482,801
Total long-term liabilities	9,899,592	36,401,360
TOTAL LIABILITIES	58,656,759	56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,624,714 and 10,603,802 shares issued at December 31, 2016 and December 31, 2015, respectively)	106,248	106,038
Additional paid-in capital	36,818,528	36,738,737
Accumulated deficit	(19,421,517)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	16,703,259	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 75,360,018	$ 89,020,714

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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	10,603,802
Common stock, shares outstanding	10,624,714	10,603,802
Treasury stock, shares	150,000	150,000

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 165,413,778	$ 220,438,588
Tank rental revenue	2,366,548	1,147,568
Pipeline operations	74,990	146,464
Total revenue from operations	167,855,316	221,732,620
COST OF OPERATIONS
Cost of refined products sold	161,714,526	193,216,959
Refinery operating expenses	12,040,676	11,683,658
Joint Marketing Agreement profit share	359,260	5,820,329
Pipeline operating expenses	340,550	(142,250)
Lease operating expenses	45,043	30,023
General and administrative expenses	2,708,594	1,525,577
Depletion, depreciation and amortization	1,935,644	1,647,586
Impairment expense	968,684	0
Bad debt expense	(139,868)	139,874
Accretion expense	112,744	211,375
Total cost of operations	180,085,853	214,133,131
Income (loss) from operations	(12,230,537)	7,599,489
OTHER INCOME (EXPENSE)
Easement, interest and other income	1,924,893	980,266
Interest and other expense	(1,854,567)	(1,742,214)
Total other expense	70,326	(761,948)
Income (loss) before income taxes	(12,160,211)	6,837,541
Income tax expense	(3,607,237)	(2,434,302)
Net income (loss)	$ (15,767,448)	$ 4,403,239
Income (loss) per common share
Basic	$ (1.51)	$ 0.42
Diluted	$ (1.51)	$ 0.42
Weighted average number of common shares outstanding:
Basic	10,464,061	10,451,832
Diluted	10,464,061	10,451,832

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, 2014	10,599,444			(150,000)
Beginning Balance, amount at Dec. 31, 2014	$ 105,995	$ 36,718,781	$ (8,057,308)	$ (800,000)	$ 27,967,468
Common stock issued for services, shares	4,358
Common stock issued for services, amount	$ 43	19,956			19,999
Net income (loss)			4,403,239		4,403,239
Ending Balance, shares at Dec. 31, 2015	10,603,802			(150,000)
Ending Balance, amount at Dec. 31, 2015	$ 106,038	36,738,737	(3,654,069)	$ (800,000)	32,390,706
Net income (loss)			(15,767,448)		(15,767,448)
Ending Balance, shares at Dec. 31, 2016	10,603,802			(150,000)
Ending Balance, amount at Dec. 31, 2016	$ 106,038	$ 36,738,737	$ (19,421,517)	$ (800,000)	$ 16,703,259

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES
Net income (loss)	$ (15,767,448)	$ 4,403,239
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,935,644	1,647,586
Unrealized loss (gain) on derivatives	(183,400)	679,300
Deferred tax expense	3,607,237	2,152,869
Amortization of debt issue costs	128,485	544,607
Accretion expense	112,744	211,375
Common stock issued for services	80,001	19,999
Recovery of bad debt	(139,868)	139,874
Impairment of fixed assets	968,684	0
Changes in operating assets and liabilities
Accounts receivable	3,574,947	2,883,058
Accounts receivable, related party	(1,161,589)
Prepaid expenses and other current assets	95,449	(168,232)
Deposits and other assets	1,073,457	293,084
Inventory	5,732,780	(4,607,667)
Accounts payable, accrued expenses and other liabilities	(4,006,063)	(272,062)
Accounts payable, related party	69,600	(874,168)
Net cash provided by (used in) operating activities	(3,879,340)	7,052,862
INVESTING ACTIVITIES
Capital expenditures	(14,100,897)	(11,370,993)
Net cash used in investing activities	(14,100,897)	(11,370,993)
FINANCING ACTIVITIES
Proceeds from issuance of debt	7,118,969	38,000,000
Payments on debt	(3,701,616)	(12,881,612)
Change in debt issue costs, net	0	(2,456,352)
Net cash provided by (used in) financing activities	3,417,353	22,662,036
Net increase (decrease) in cash, cash equivalents, and restricted cash	(14,562,884)	18,343,905
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD	20,645,652	2,301,747
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD	6,082,768	20,645,652
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	2,286,082	873,665
Interest paid	2,357,237	1,608,808
Income taxes paid	$ 0	$ 139,500

1. Organization

1. Organization	12 Months Ended
	Dec. 31, 2016
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 (“BDPL”), a Delaware corporation. ● Blue Dolphin Petroleum Company, a Delaware corporation. ● Blue Dolphin Services Co., a Texas corporation. See "Part I, Item 1. Business and Item 2. Properties” within this Annual Report on Form 10-K (this “Annual Report”) 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. Operating Risks – Going Concern ● Net Losses – For the year ended December 31, 2016, we reported a net loss of $15,767,448, or a loss of $1.51 per share, compared to net income of $4,403,239, or income of $0.42 per share, for the year ended December 31, 2015. The $1.93 per share decrease in net income between the periods was the result of lower margins on refined petroleum products, lower refinery throughput, higher refinery operating expenses, and income tax expense. Margins on refined petroleum products decreased primarily because of lower crack spreads. ● Working Capital Deficits – We had a working capital deficit of $37,812,263 at December 31, 2016 compared to a working capital deficit of $598,807 at December 31, 2015. The significant increase in working capital deficit between the periods primarily related to reclassification of secured long-term debt (and the related debt issue costs) with Sovereign Bank (“Sovereign”) to the current portion within long-term debt. Excluding long-term debt, we had a working capital deficit of $6,099,927 at December 31, 2016, compared to a working capital deficit of $598,807 at December 31, 2015. The significant increase in working capital deficit between the periods was primarily the result of sustaining net losses in 2016 compared to net income in 2015 as described above. ● Adverse Change in Relationship with Genesis Energy, LLP (“Genesis”) and GEL Tex Marketing, LLC (“GEL”) – We are party to a variety of contracts and agreements with Genesis and GEL for the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. We currently have a contract-related dispute with GEL related to certain of these agreements. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. ● Crude Supply Issues – Historically, we purchased light crude oil and condensate for the Nixon Facility from GEL pursuant to a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”). As noted above, we are currently involved in a contract-related dispute with GEL related to the Crude Supply Agreement. In connection with this dispute, GEL significantly under-delivered crude oil and condensate to the Nixon Facility during 2016. This resulted in 59 days of refinery downtime and a significant decrease in refinery throughput and refined petroleum product sales for the year ended December 31, 2016. Consequently, we ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier. We believe that adequate supplies of crude oil and condensate for the Nixon Facility will continue to be available to us from the alternate supplier. We are working to put a long-term crude supply agreement in place, however, our ability to purchase adequate supplies 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. ● Financial Covenant Defaults – At December 31, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign. Covenant defaults under the secured loan agreements would permit Sovereign to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the year ended December 31, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2016 due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. We are taking aggressive actions to improve operations and liquidity by: (i) continuing with Nixon Facility capital improvements, including upgrading the refinery’s heat exchangers and increasing petroleum storage tank capacity, (ii) increasing military jet fuel sales and low-sulfur diesel exports to Mexico, (iii) restructuring customer contracts as they come up for renewal to incorporate minimum sales volumes, (iv) working to secure a long-term crude oil and condensate supply arrangement, (v) exploring alternative funding sources for crude oil and condensate purchases, and (vi) seeking additional financing to meet ongoing liquidity needs. There can be no assurance that our plan will be successful or that we will be able to obtain additional financing on commercially reasonable terms or at all. For additional disclosures related to our agreements and the contract-related dispute with GEL, financial covenant violations, and risk factors that could materially affect our future results of operations, refer to the following sections within this Annual Report: ● Part I, Item 1A. Risk Factors ● Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Key Relationships – Relationship with Genesis and GEL – Results of Operations – Non-GAAP Financial Measures ● Part II, Item 8. Financial Statements and Supplementary Data: – Note (10) Long-Term Debt, Net – Note (20) Commitments and Contingencies – Genesis Agreements and Legal Matters – Note (21) Subsequent Events

2. Basis of Presentation

2. Basis of Presentation	12 Months Ended
	Dec. 31, 2016
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, 2016
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 Derivatives Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements under which we are exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets, and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting. (See “Note (18) Fair Value Measurement” and “Note (19) Inventory Risk Management” for additional disclosures related to derivatives.) 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. We did not record any impairment of our refinery and facilities assets for any period presented. Pipelines and Facilities Management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, we recorded an impairment expense of $968,684 related to our pipeline assets at December 31, 2016. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines. Oil and Gas Properties 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 Deferred 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, 2016. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2016. FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. (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.) Stock-Based Compensation Treasury Stock New Pronouncements Adopted ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (a Consensus of the FASB Emerging Issues Task Force ASU 2015-17, Income Taxes (Topic 740) ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). New Pronouncements Issued, Not Yet Effective ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments) ASU 2016-02, Leases (Topic 842) ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory ASU 2014-09, Revenue from Contracts with Customers (Topic 606) ● ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date; ● ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net); ● ASU 2016-10 Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing; ● ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update); ● ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients; ● ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, ASU 2016-12, and ASU 2016-20, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements. Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity. Reclassification

4. Business Segment Information

4. Business Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Business Segment Information	We have two reportable business segments: (i) Refinery Operations and (ii) Pipeline Transportation. Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility. Business activities related to our Pipeline Transportation business segment are primarily conducted in the Gulf of Mexico through our pipeline assets and leasehold interests in oil and gas properties. Business segment information for the periods indicated (and as of the dates indicated), was as follows: Years Ended December 31, 2016 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 167,780,326 $ 74,990 $ — $ 167,855,316 $ 221,586,156 $ 146,464 $ — $ 221,732,620 Less: cost of operations(1) (175,340,816 ) (1,467,021 ) (983,112 ) (177,790,949 ) (205,403,355 ) (45,931 ) (1,215,929 ) (206,665,215 ) Other non-interest income(2) — 1,914,607 — 1,914,607 — 312,500 660,000 972,500 Adjusted EBITDA(3) (7,560,490 ) 522,576 (983,112 ) (8,021,026 ) 16,182,801 413,033 (555,929 ) 16,039,905 Less: JMA Profit Share(4) (359,260 ) — — (359,260 ) (5,820,329 ) — — (5,820,329 ) EBITDA(3) $ (7,919,750 ) $ 522,576 $ (983,112 ) $ 10,362,472 $ 413,033 $ (555,929 ) Depletion, depreciation and amortization (1,935,644 ) (1,647,586 ) Interest expense, net (1,844,281 ) (1,734,449 ) Income (loss) before income taxes (12,160,211 ) 6,837,541 Income tax expense (3,607,237 ) (2,434,302 ) Net income (loss) $ (15,767,448 ) $ 4,403,239 Capital expenditures $ 16,386,979 $ — $ — $ 16,386,979 $ 12,244,658 $ — $ — $ 12,264,658 Identifiable assets(5) $ 74,236,629 $ 763,596 $ 359,793 $ 75,360,018 $ 82,605,078 $ 2,338,107 $ 4,077,529 $ 89,020,714 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within the Pipeline Transportation segment includes related impairment expense. 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. (2) Other non-interest income reflects FLNG Land II, Inc. (“FLNG”) easement revenue. (See “Note (20) Commitments and Contingencies – FLNG Easement Agreements” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (20) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement and the contract-related dispute with GEL.) (5) Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

5. Prepaid Expenses and Other C

5. Prepaid Expenses and Other Current Assets	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Short-term tax bond $ 505,000 $ — Prepaid exise taxes 292,338 — Prepaid insurance 248,853 315,120 Prepaid related party operating expenses — 624,570 Unrealized hedging gains — — $ 1,046,191 $ 939,690

6. Inventory

6. Inventory	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: December 31, 2016 2015 Jet fuel $ 964,124 $ 309,850 Naphtha 533,580 5,007,576 HOBM 212,987 2,045,784 Chemicals 182,751 278,278 AGO 143,362 122,777 Crude oil and condensate 26,123 7,152 Propane 11,318 17,860 LPG mix 1,293 19,041 $ 2,075,538 $ 7,808,318

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Refinery and facilities $ 50,814,309 $ 40,195,928 Pipelines and facilities — 2,127,207 Onshore separation and handling facilities — 325,435 Land 602,938 602,938 Other property and equipment 652,795 644,795 52,070,042 43,896,303 Less: Accumulated depletion, depreciation, and amortization (6,685,244 ) (6,234,161 ) 45,384,798 37,662,142 Construction in progress 16,939,665 11,179,670 $ 62,324,463 $ 48,841,812 We capitalize interest cost incurred on funds used to construct property, plant, and equipment. The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life. Interest cost capitalized was $2,108,298 and $556,032 at December 31, 2016 and 2015, respectively.

8. Related Party Transactions

8. Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Agreement Summaries LEH Operating Agreement ● Reimbursements – ● Fees – Product Sales Agreement Terminal Services Agreement 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 located in Brazoria County Texas (the "BDPL Property"). Outstanding principal and interest less associated debt issue costs owed to LEH under the LEH Loan Agreement are reflected in long-term debt, related party, current portion and long-term debt, related party, net of current portion in our consolidated balance sheets. Promissory Note Ingleside Crude, LLC (“Ingleside”) Amended and Restated Tank Lease Agreement Promissory Note Lazarus Marine Terminal I, LLC (“LMT”) Tolling Agreement Jonathan Carroll Guaranty Fee Agreements Promissory Note Financial Statements Impact Consolidated Balance Sheets December 31, 2016 2015 LEH $ — $ 624,570 $ — $ 624,570 Accounts payable, related party to Ingleside associated with the Amended and Restated Tank Lease Agreement and to LMT associated with the Tolling Agreement as of the dates indicated was as follows: December 31, 2016 2016 2015 Ingleside $ — $ 300,000 LMT 369,600 — $ 369,600 $ 300,000 Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows: December 31, 2016 2015 LEH $ 4,000,000 $ — Ingleside 722,278 — Jonathan Carroll 592,412 — 5,314,690 — Less: Long-term debt, related party, current portion (500,000 ) — $ 4,814,690 $ — Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows: December 31, 2016 2015 LEH $ 243,556 $ — 243,556 — Less: Interest payable, current portion (243,556 ) — $ — $ — Consolidated Statements of Operations Years Ended December 31, 2016 2015 Refined petroleum product sales LEH $ 43,904,790 $ — Other customers 121,508,988 220,438,588 Total refined petroleum product sales 165,413,778 220,438,588 Tank rental revenue LEH 1,125,000 — Other customers 1,241,548 1,147,568 Total tank rental revenue 2,366,548 1,147,568 Pipeline operations Other customers 74,990 146,464 Total revenue from operations $ 167,855,316 $ 221,732,620 Related party cost of goods sold associated with the Tolling Agreement with LMT for the periods indicated were as follows: Years Ended December 31, 2016 2015 LMT $ 369,600 $ — $ 369,600 $ — Related party refinery operating expenses associated with the 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, 2016 2015 Amount Per bbl Amount Per bbl LEH $ 11,140,676 $ 3.10 $ 11,333,658 $ 2.71 Ingleside 900,000 $ 0.25 350,000 $ 0.09 Jonathan Carroll — — $ 12,040,676 $ 3.35 $ 11,683,658 $ 2.80 Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated was as follows: Years Ended December 31, 2016 2015 Jonathan Carroll $ 692,969 $ 320,123 LEH 243,556 — Ingleside — — $ 936,525 $ 320,123

9. Accrued Expenses and Other C

9. Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Customer deposits $ 450,000 $ 157,714 Unearned revenue 408,770 781,859 Other payable 189,719 103,024 Board of director fees payable 136,429 1,290,101 Insurance 67,783 — Excise and income taxes payable 24,187 388,364 Property taxes 4,694 — Genesis JMA Profit Share payable — 86,429 Transportation and inspection — 183,400 $ 1,281,582 $ 2,990,891

10. Long-Term Debt, Net

10. Long-Term Debt, Net	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt, Net	Effective January 1, 2016, we adopted the provisions of the FASB ASC guidance that requires debt issue costs to be presented as an offset to their related debt. Accordingly, our consolidated balance sheet at December 31, 2015 was changed to reclassify approximately $2.4 million previously reported debt issue costs as a direct deduction of long-term debt. Long-term debt, net, which includes related-party, represents the outstanding principal and interest of our long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following: December 31, 2016 2015 First Term Loan Due 2034 $ 23,924,607 $ 24,643,081 Second Term Loan Due 2034 9,729,853 10,000,000 LEH Loan Agreement 4,000,000 — Ingleside Note 722,278 — Notre Dame Debt 1,300,000 1,300,000 Carroll Note 592,412 Term Loan Due 2017 184,994 924,969 Capital Leases 135,879 304,618 $ 40,590,023 $ 37,172,668 Less: Long-term debt less unamortized debt issue costs and long-term debt, related party, current portion (32,212,336 ) (1,934,932 ) Less: unamortized debt issue costs (2,262,997 ) (2,391,482 ) $ 6,114,690 $ 32,846,254 Debt issue costs are capitalized and amortized over the terms of the underlying loan using the effective-interest method. Debt issue costs at December 31, 2016 and 2015 related to secured loan agreements with Sovereign. December 31, 2016 2015 First Term Loan Due 2034 $ 1,673,545 $ 1,673,545 Second Term Loan Due 2034 767,673 767,673 Less: Accumulated amortization (178,221 ) (49,736 ) $ 2,262,997 $ 2,391,482 Amortization expense, which is included in interest expense, was $128,233 and $544,607 for the years ended December 31, 2016 and 2015, respectively. Amortization expense for the year ended December 31, 2015 included $456,287 related to writing off debt issue costs associated with the refinance of debt owed to American First National Bank. Accrued interest associated with our 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, 2016 2015 Notre Dame Debt $ 1,691,383 $ 1,482,801 LEH Loan Agreement 243,556 — Second Term Loan Due 2034 44,984 39,193 First Term Loan Due 2034 33,866 34,883 Capital Leases 1,165 2,612 Term Loan Due 2017 185 4,779 2,015,139 1,564,268 Less: Interest payable, current portion (323,756 ) (81,467 ) $ 1,691,383 $ 1,482,801 At December 31, 2016, our expected future long-term debt payments were as follow: 2017 $ 34,475,333 2018 6,114,690 2019 — 2020 — 2021 — Subsequent to 2021 — $ 40,590,023 (See “Note (8) Related Party Transactions” for additional disclosures with respect to related party long-term debt.) First Term Loan Due 2034 providing for a term loan in the principal amount of $25.0 million At December 31, 2016, 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. Consequently, Sovereign could 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. Sovereign waived the financial covenant defaults as of the year ended December 31, 2016. However, the debt associated with the loan was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2016 due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks-Going Concern” and “Note (21) Subsequent Events” for additional disclosures related to the First Term Loan Due 2034 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 $1.0 million payment reserve account held by Sovereign, 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 At December 31, 2016, LRM was in violation of the debt service coverage ratio, the current ratio, and the debt to net worth ratio financial covenants related to the Second Term Loan Due 2034. Consequently, Sovereign could 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. Sovereign waived the financial covenant defaults as of the year ended December 31, 2016. However, the debt associated with the loan was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2016 due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks-Going Concern” and “Note (21) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.) As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034. For the years ended December 31, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $197,024 and $16,667, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Sovereign 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 Sovereign has a second priority lien in such leases subordinate to a prior lien granted by LRM to Sovereign to secure obligations of LRM under the 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. LEH Loan 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 the BDPL Property. Outstanding principal and interest less associated debt issue costs owed to LEH under the LEH Loan Agreement are reflected in long-term debt, related party, current portion and long-term debt, related party, net of current portion in our consolidated balance sheets. Ingleside Note Notre Dame Debt The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Sovereign as holder of the First Term Loan Due 2034. Carroll Note Term Loan Due 2017 At December 31, 2016, LRM was in violation of the debt service coverage ratio financial covenant related to the Term Loan Due 2017. Consequently, Sovereign could declare the amounts owed under the Term Loan Due 2017 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. The Term Loan Due 2017 was already classified within the current portion of long-term debt on our consolidated balance sheets due to the loan’s short-term maturity date. Sovereign waived the financial covenant default as of the year ended December 31, 2016. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks-Going Concern” and “Note (21) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.) As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee r epayment The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and certain assets of LEH. (See “Note (8) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) Capital Leases A summary of equipment held under long-term capital leases as of the dates indicated follows: December 31, 2016 2015 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation — — $ 538,598 $ 538,598 At December 31, 2016, future minimum lease commitments under non-cancelable capital leases were as follow: 2017 $ 138,310 Less: amount representing interest (2,431 ) Present value of minimum lease payments $ 135,879 At December 31, 2016, the present value of minimum lease payments due within one year was $135,879.

11. Asset Retirement Obligation

11. Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Asset retirement obligations, at the beginning of the period $ 1,985,864 $ 1,866,770 New asset retirement obligations and adjustments — 49 Liabilities settled (70,969 ) (92,330 ) Accretion expense 112,744 211,375 2,027,639 1,985,864 Less: asset retirement obligations, current portion (17,510 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 2,010,129 $ 1,947,220 Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability and are reflected in our consolidated balance sheets. At December 31, 2016 and 2015, we recognized $70,969 and $92,330, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability and are reflected in our consolidated statements of operations. For the years ended December 31, 2016 and 2015, we recognized $0 in abandonment expense.

12. Impairment

12. Impairment	12 Months Ended
	Dec. 31, 2016
Impairment
Impairment	For the years ended December 31, 2016 and 2015, we recorded impairment expense of $968,684 and $0, respectively. The impairment expense for the year ended December 31, 2016 related to our pipeline fixed assets. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines.

13. Treasury Stock

13. Treasury Stock	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Treasury Stock	At December 31, 2016 and 2015, we had 150,000 shares of treasury stock.

14. Concentration of Risk

14. Concentration of Risk	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier Historically, we purchased light crude oil and condensate for the Nixon Facility from GEL pursuant to a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”). The Crude Supply Agreement automatically renews for successive one-year terms until August 2019 unless GEL provides us with notice of nonrenewal at least 180 days prior to expiration of any renewal term. The parties are currently involved in a contract-related dispute. Therefore, we ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier. (See “Part I, Item 1A. Risk Factors” as well as “Note (20) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” for disclosures related to the Crude Supply Agreement and the current contract-related dispute with GEL.) In June 2016, we entered a month-to-month evergreen crude supply contract with a major integrated oil and gas company as back-up to the Crude Supply Agreement with GEL. We believe that adequate supplies of crude oil and condensate for the Nixon Facility will continue to be available to us from the alternate supplier. We are working to put a long-term crude supply agreement in place, 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. Significant Customers For the year ended December 31, 2016, we had 4 customers that accounted for approximately 67% of our refined petroleum product sales. At December 31, 2016, these 4 customers represented approximately $1.6 million in accounts receivable. For the year ended December 31, 2015, we had 3 customers that accounted for approximately 56% of our refined petroleum products sales. At December 31, 2015, these 3 customers represented approximately $3.0 million in accounts receivable. For the year ended December 31, 2016, LEH, a related party, was 1 of our 4 significant customers. LEH accounted for approximately 27% of our refined petroleum product sales for the year ended December 31, 2016. LEH, which resells jet fuel to a government agency, represented approximately $1.6 million in accounts receivable at December 31, 2016. LEH was not a significant customer during 2015. (See “Note (8) Related Party Transactions” for additional disclosures with respect to related parties.) Refined Petroleum Product Sales Years Ended December 31, 2016 2015 LPG mix $ 714,285 0.4 % $ 1,253,826 0.6 % Naphtha 35,544,394 21.5 % 48,410,300 22.0 % Jet fuel 55,459,227 33.5 % 67,085,046 30.4 % HOBM 35,924,098 21.8 % 46,936,751 21.3 % Reduced Crude 3,791,919 2.3 % 3,838,273 1.7 % AGO 33,979,855 20.5 % 52,914,392 24.0 % $ 165,413,778 100.0 % $ 220,438,588 100.0 %

15. Leases

15. Leases	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Leases	Our company headquarters is in downtown Houston, Texas. We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10-year term that expires in September 2017. The lease included a free rent period, has escalating rent payment provisions, and requires payment of a portion of operating expenses. Rent expense is recognized on a straight-line basis. For the years ended December 31, 2016 and 2015, rent expense totaled $142,604 and $142,604, respectively. At December 31, 2016, future minimum lease commitments that were non-cancelable under our office lease were as follow: Years Ending December 31, 2017 $ 128,852

16. Income Taxes

16. Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Benefit (Expense) Years Ended December 31, 2016 2015 Current: Federal $ — $ (111,566 ) State — (169,867 ) Deferred: Federal (3,607,237 ) (2,152,869 ) State — — $ (3,607,237 ) $ (2,434,302 ) 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 2016 2015 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 0.00 % 1.64 % Federal tax 0.00 % 0.01 % Change in valuation allowance (63.66 )% 0.00 % (29.66 )% 35.65 % 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, 2014 $ 10,766,912 $ 12,145,789 $ 22,912,701 Net operating loss carryforwards utilized (1,152,463 ) (2,528,848 ) (3,681,311 ) — 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 Deferred Tax Assets and Liabilities December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 13,550,338 $ 8,815,794 Start-up costs (Nixon Facility) 1,373,363 1,510,699 Asset retirement obligations liability/deferred revenue 717,751 717,723 Unrealized hedges — 62,356 AMT credit and other 266,522 302,086 Total deferred tax assets 15,907,974 11,408,658 Deferred tax liabilities: Fair market value adjustments — (46,116 ) Unrealized hedges — — Basis differences in property and equipment (5,895,943 ) (5,484,983 ) Total deferred tax liabilities (5,895,943 ) (5,531,099 ) 10,012,031 5,877,559 Valuation allowance (10,012,031 ) (2,270,322 ) Deferred tax assets, net $ — $ 3,607,237 Valuation Allowance Current Versus Long-Term Uncertain Tax Positions As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2016 and 2015. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2013, or after and by the state of Texas for tax years ending December 31, 2012, or after. We believe there are no uncertain tax positions for both federal and state income taxes.

17. Earnings Per Share

17. Earnings Per Share	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Net income (loss) $ (15,767,448 ) $ 4,403,239 Basic and diluted income per share $ (1.51 ) $ 0.42 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,464,061 10,451,832 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, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

18. Fair Value Measurement

18. Fair Value Measurement	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	We may purchase and execute the sale of financial instruments to economically hedging commodity price risks associated with our refined petroleum products and the purchase of crude oil and condensate. We account for derivatives in our financial records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions involving identical or comparable assets or liabilities. Generally accepted accounting principles establish a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The fair value hierarchy consists of the following three levels: Level 1 Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data. Level 3 Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs. The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2016 and 2015 due to their short-term maturities. The fair value of our long-term debt, net (including both the current and non-current portions of long-term debt and related party) at December 31, 2016 and 2015 was $40,590,023 and $37,172,668, respectively. The fair value of our debt was determined using a Level 3 hierarchy. The following table represents our assets and liabilities measured at fair value on a recurring basis at December 31, 2016 and 2015 and the basis for the measurement: Fair Value Measurement at December 31, 2016 Using Financial assets (liabilities): Carrying Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs Commodity contracts $ — $ — $ — $ — Fair Value Measurement at December 31, 2015 Using Financial assets (liabilities): Carrying Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs Commodity contracts $ (183,400 ) $ (183,400 ) $ — $ — Carrying amounts of commodity contracts are reflected as other current assets or other current liabilities in our consolidated balance sheets.

19. Inventory Risk Management

19. Inventory Risk Management	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Inventory Risk Management	Management periodically determines whether to maintain, increase, or decrease inventory levels based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows. Under our inventory risk management policy, commodity futures contracts may be used to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled with cash. The fair value of commodity futures contracts is reflected in our consolidated balance sheets and the related net gain or loss is recorded within cost of refined products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for marking to market the financial instruments at each period end. Commodity transactions are executed to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. Due to mark-to-market accounting during the term of the commodity futures contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations. At December 31, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered as economic hedges. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in bbls): Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2016 2017 2018 Refined petroleum products and crude oil - net short positions — — — The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at December 31, 2016 and 2015: Fair Value December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets $ — $ (183,400 ) The following table provides the effect of derivative instruments in our consolidated statements of operations for the years ended December 31, 2016 and 2015: Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2016 2015 Commodity contracts Cost of refined products sold $ (2,445,898 ) $ 3,730,613

20. Commitments and Contingenci

20. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Operating Agreement Genesis Agreements Crude Supply Agreement Joint Marketing Agreement ● We were entitled to receive weekly operations payments to cover direct expenses in operating the Nixon Facility in an amount not to exceed $750,000 per month. In addition, we were entitled to receive reimbursement for accounting fees, if incurred, not to exceed $50,000 per month. We assigned our rights to the operations payments and reimbursement of accounting fees under the Joint Marketing Agreement to LEH pursuant to the Operating Agreement; and ● GEL was entitled to receive an administrative fee in the amount of $150,000 per month relating to the performance of its obligations under the Joint Marketing Agreement (the “Performance Fee”). GEL was entitled to receive 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share, and we were entitled to receive 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeded the Threshold Amount for a calendar month was payable to GEL and us in the following manner: (i) GEL was entitled to receive 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we were entitled to receive 80% of the remaining Gross Profits over the Threshold Amount as our Profit Share. The GEL Profit Share plus the Performance Fee are collectively referred to herein as the “Joint Marketing Agreement Profit Share” or the “JMA Profit Share”. The Crude Supply Agreement and Joint Marketing Agreement automatically renew for successive one-year terms until August 2019 unless GEL provides us with notice of nonrenewal at least 180 days prior to expiration of any renewal term. The parties are currently involved in a contract-related dispute. Consequently, we ceased purchases of crude oil and condensate from GEL in November 2016. Following the marketing and sale of all refined petroleum products processed through the Nixon Facility using GEL supplied crude oil and condensate, we suspended use of GEL’s services under the Joint Marketing Agreement. Pursuant to a Letter Agreement Regarding Subordination of GEL Transaction Documents dated in June 2015, we, among other things, assigned our rights to payments under the Crude Supply Agreement and Joint Marketing Agreement as collateral in favor of Sovereign Bank, as lender and lienholder pursuant to the First Term Loan Due 2034. (See “Note (10) Long-Term Debt, Net” for further discussion related to the First Term Loan Due 2034.) GEL Contract-Related Dispute FLNG Easement Agreements Supplemental Pipeline Bonds In October 2016, we received a letter from the BOEM summarizing the amount required as additional security on our existing pipeline rights-of-way. The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental pipeline bonds or acceptable financial reassurance of approximately $4.6 million. At December 31, 2016 and 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. Of the 5 rights-of-ways reflected in the BOEM’s October 2016 letter, one right-of-way was abandoned-in-place in 1997. We requested permits from the Bureau of Safety and Environmental Enforcement (the “BSEE”) to decommission and abandon-in-place 3 of the rights-of-way in April 2016, one of which also requires approval from the U.S. Army Corps of Engineers. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. Financing Agreements Grynberg Settlement Agreement Mutual Release Agreement and Withdrawal of All Qui Tam Claims Nixon Facility Expansion e Legal Matters GEL Contract-Related Dispute. In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the “Petition”) against LE and LEH. The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, in connection with an agreement by LEH to supply jet fuel acquired from LE to a government agency. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GEL’s claims in the Petition are without merit and is defending the matter vigorously. In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of a Dispute Resolution Agreement between the parties (the “Arbitration”). The Arbitration alleges that GEL breached the Crude Supply Agreement by: (i) overcharging for crude oil and condensate based on Genesis’ cost as defined in the Crude Supply Agreement, (ii) overcharging for trucking costs, and (iii) significantly under-delivering crude oil and condensate, resulting in 59 days of refinery downtime and significant decreases in refinery throughput, refinery production, and refined petroleum product sales for the year ended December 31, 2016. GEL has made counter claims in the Arbitration with allegations against LE similar to those made in the Petition. GEL is seeking substantial damages, as well as recovery of attorneys’ fee and costs, totaling approximately $44.0 million in the aggregate, based on allegations of breach of contract, fraudulent transfer and unjust enrichment. We believe GEL’s counter claims are without merit and are defending them vigorously in the Arbitration. However, any determination by the arbitrator that we owe significant damages to GEL would have a material adverse effect on our business, liquidity and financial condition and results of operations. If GEL were awarded significant damages, we may not be able to pay such damages, which would affect our ability to continue as a going concern. A hearing date to discuss and attempt to resolve the Petition and Arbitration was set for February 2017, however, the hearing date was rescheduled to April 2017. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet at December 31, 2016. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. Other Legal Matters Health, Safety and Environmental Matters

21. Subsequent Events

21. Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Financial Covenant Defaults By letter dated March 29, 2017, Sovereign waived the financial covenant defaults as of the year ended December 31, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. Termination of FLNG Easements, Acceleration of Payment Obligations, Land Sale In connection with entry into the FLNG Master Easement Agreement, BDPL and FLEX entered a Letter of Intent dated December 11, 2013 (the "Letter of Intent"), pursuant to which BDPL and FLEX committed to study the feasibility of jointly developing facilities to source and supply liquefied natural gas for sale to third parties for use as transportation fuel in the U.S. domestic transportation markets. In connection with the sale of real estate, BDPL and FLEX terminated the Letter of Intent. No definitive agreements for any transaction contemplated by the Letter of Intent were entered between the parties prior to the termination of the Letter of Intent.

3. Significant Accounting Pol28

3. Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable, Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
Inventory	Inventory
Derivatives	Derivatives Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements under which we are exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets, and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting. (See “Note (18) Fair Value Measurement” and “Note (19) Inventory Risk Management” for additional disclosures related to derivatives.)
Property and Equipment	Property and Equipment Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. We did not record any impairment of our refinery and facilities assets for any period presented. Pipelines and Facilities Management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, we recorded an impairment expense of $968,684 related to our pipeline assets at December 31, 2016. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines. Oil and Gas Properties 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	Intangibles – Other
Debt Issue Costs	Debt Issue Costs
Revenue Recognition	Revenue Recognition Refined Petroleum Products Revenue Tank Rental Revenue Easement Revenue Pipeline Transportation Revenue Deferred Revenue
Income Taxes	Income Taxes As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that a portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2016. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a full valuation allowance against the deferred tax assets as of December 31, 2016. FASB ASC guidance related to income taxes also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. (See “Note (16) Income Taxes” for further information related to income taxes.)
Impairment or Disposal of Long-Lived Assets	Impairment or Disposal of Long-Lived Assets
Asset Retirement Obligations	Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (11) Asset Retirement Obligations” for additional information related to our AROs.)
Computation of Earnings Per Share	Computation of Earnings Per Share The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (17) Earnings Per Share” for additional information related to EPS.)
Stock-Based Compensation	Stock-Based Compensation
Treasury Stock	Treasury Stock
New Pronouncements Adopted	New Pronouncements Adopted ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (a Consensus of the FASB Emerging Issues Task Force ASU 2015-17, Income Taxes (Topic 740) ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40).
New Pronouncements Issued, Not Yet Effective	New Pronouncements Issued, Not Yet Effective ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments) ASU 2016-02, Leases (Topic 842) ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory ASU 2014-09, Revenue from Contracts with Customers (Topic 606) ● ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date; ● ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net); ● ASU 2016-10 Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing; ● ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update); ● ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients; ● ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, ASU 2016-12, and ASU 2016-20, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements. Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity.
Reclassification	Reclassification

4. Business Segment Informati29

4. Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Business segment reporting	Years Ended December 31, 2016 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 167,780,326 $ 74,990 $ — $ 167,855,316 $ 221,586,156 $ 146,464 $ — $ 221,732,620 Less: cost of operations(1) (175,340,816 ) (1,467,021 ) (983,112 ) (177,790,949 ) (205,403,355 ) (45,931 ) (1,215,929 ) (206,665,215 ) Other non-interest income(2) — 1,914,607 — 1,914,607 — 312,500 660,000 972,500 Adjusted EBITDA(3) (7,560,490 ) 522,576 (983,112 ) (8,021,026 ) 16,182,801 413,033 (555,929 ) 16,039,905 Less: JMA Profit Share(4) (359,260 ) — — (359,260 ) (5,820,329 ) — — (5,820,329 ) EBITDA(3) $ (7,919,750 ) $ 522,576 $ (983,112 ) $ 10,362,472 $ 413,033 $ (555,929 ) Depletion, depreciation and amortization (1,935,644 ) (1,647,586 ) Interest expense, net (1,844,281 ) (1,734,449 ) Income (loss) before income taxes (12,160,211 ) 6,837,541 Income tax expense (3,607,237 ) (2,434,302 ) Net income (loss) $ (15,767,448 ) $ 4,403,239 Capital expenditures $ 16,386,979 $ — $ — $ 16,386,979 $ 12,244,658 $ — $ — $ 12,264,658 Identifiable assets(5) $ 74,236,629 $ 763,596 $ 359,793 $ 75,360,018 $ 82,605,078 $ 2,338,107 $ 4,077,529 $ 89,020,714 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within the Pipeline Transportation segment includes related impairment expense. 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. (2) Other non-interest income reflects FLNG Land II, Inc. (“FLNG”) easement revenue. (See “Note (20) Commitments and Contingencies – FLNG Easement Agreements” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (20) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement and the contract-related dispute with GEL.) (5) Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

5. Prepaid Expenses and Other30

5. Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Liabilities extinguished
Prepaid expenses and other current assets	December 31, 2016 2015 Short-term tax bond $ 505,000 $ — Prepaid exise taxes 292,338 — Prepaid insurance 248,853 315,120 Prepaid related party operating expenses — 624,570 Unrealized hedging gains — — $ 1,046,191 $ 939,690

6. Inventory (Tables)

6. Inventory (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventory	December 31, 2016 2015 Jet fuel $ 964,124 $ 309,850 Naphtha 533,580 5,007,576 HOBM 212,987 2,045,784 Chemicals 182,751 278,278 AGO 143,362 122,777 Crude oil and condensate 26,123 7,152 Propane 11,318 17,860 LPG mix 1,293 19,041 $ 2,075,538 $ 7,808,318

7. Property, Plant and Equipm32

7. Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property and equipment	December 31, 2016 2015 Refinery and facilities $ 50,814,309 $ 40,195,928 Pipelines and facilities — 2,127,207 Onshore separation and handling facilities — 325,435 Land 602,938 602,938 Other property and equipment 652,795 644,795 52,070,042 43,896,303 Less: Accumulated depletion, depreciation, and amortization (6,685,244 ) (6,234,161 ) 45,384,798 37,662,142 Construction in progress 16,939,665 11,179,670 $ 62,324,463 $ 48,841,812

8. Related Party Transactions (

8. Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related party transactions	Financial Statements Impact Consolidated Balance Sheets December 31, 2016 2015 LEH $ — $ 624,570 $ — $ 624,570 Accounts payable, related party to Ingleside associated with the Amended and Restated Tank Lease Agreement and to LMT associated with the Tolling Agreement as of the dates indicated was as follows: December 31, 2016 2016 2015 Ingleside $ — $ 300,000 LMT 369,600 — $ 369,600 $ 300,000 Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows: December 31, 2016 2015 LEH $ 4,000,000 $ — Ingleside 722,278 — Jonathan Carroll 592,412 — 5,314,690 — Less: Long-term debt, related party, current portion (500,000 ) — $ 4,814,690 $ — Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows: December 31, 2016 2015 LEH $ 243,556 $ — 243,556 — Less: Interest payable, current portion (243,556 ) — $ — $ — Consolidated Statements of Operations Years Ended December 31, 2016 2015 Refined petroleum product sales LEH $ 43,904,790 $ — Other customers 121,508,988 220,438,588 Total refined petroleum product sales 165,413,778 220,438,588 Tank rental revenue LEH 1,125,000 — Other customers 1,241,548 1,147,568 Total tank rental revenue 2,366,548 1,147,568 Pipeline operations Other customers 74,990 146,464 Total revenue from operations $ 167,855,316 $ 221,732,620 Related party cost of goods sold associated with the Tolling Agreement with LMT for the periods indicated were as follows: Years Ended December 31, 2016 2015 LMT $ 369,600 $ — $ 369,600 $ — Related party refinery operating expenses associated with the 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, 2016 2015 Amount Per bbl Amount Per bbl LEH $ 11,140,676 $ 3.10 $ 11,333,658 $ 2.71 Ingleside 900,000 $ 0.25 350,000 $ 0.09 Jonathan Carroll — — $ 12,040,676 $ 3.35 $ 11,683,658 $ 2.80 Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated was as follows: Years Ended December 31, 2016 2015 Jonathan Carroll $ 692,969 $ 320,123 LEH 243,556 — Ingleside — — $ 936,525 $ 320,123

9. Accrued Expenses and Other34

9. Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Accrued Expenses And Other Current Liabilities Tables
Accrued expenses and other current liabilities	December 31, 2016 2015 Customer deposits $ 450,000 $ 157,714 Unearned revenue 408,770 781,859 Other payable 189,719 103,024 Board of director fees payable 136,429 1,290,101 Insurance 67,783 — Excise and income taxes payable 24,187 388,364 Property taxes 4,694 — Genesis JMA Profit Share payable — 86,429 Transportation and inspection — 183,400 $ 1,281,582 $ 2,990,891

10. Long-Term Debt, Net (Tables

10. Long-Term Debt, Net (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	December 31, 2016 2015 First Term Loan Due 2034 $ 23,924,607 $ 24,643,081 Second Term Loan Due 2034 9,729,853 10,000,000 LEH Loan Agreement 4,000,000 — Ingleside Note 722,278 — Notre Dame Debt 1,300,000 1,300,000 Carroll Note 592,412 Term Loan Due 2017 184,994 924,969 Capital Leases 135,879 304,618 $ 40,590,023 $ 37,172,668 Less: Long-term debt less unamortized debt issue costs and long-term debt, related party, current portion (32,212,336 ) (1,934,932 ) Less: unamortized debt issue costs (2,262,997 ) (2,391,482 ) $ 6,114,690 $ 32,846,254
Debt issue costs	December 31, 2016 2015 First Term Loan Due 2034 $ 1,673,545 $ 1,673,545 Second Term Loan Due 2034 767,673 767,673 Less: Accumulated amortization (178,221 ) (49,736 ) $ 2,262,997 $ 2,391,482
Accrued interest related to our long-term debt, net	December 31, 2016 2015 Notre Dame Debt $ 1,691,383 $ 1,482,801 LEH Loan Agreement 243,556 — Second Term Loan Due 2034 44,984 39,193 First Term Loan Due 2034 33,866 34,883 Capital Leases 1,165 2,612 Term Loan Due 2017 185 4,779 2,015,139 1,564,268 Less: Interest payable, current portion (323,756 ) (81,467 ) $ 1,691,383 $ 1,482,801
Schedule of summary of equipment held under long-term capital leases	2017 $ 34,475,333 2018 6,114,690 2019 — 2020 — 2021 — Subsequent to 2021 — $ 40,590,023
Summary of equipment held under long-term capital leases	December 31, 2016 2015 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation — — $ 538,598 $ 538,598
Future minimum lease commitments under non-cancelable capital leases	2017 $ 138,310 Less: amount representing interest (2,431 ) Present value of minimum lease payments $ 135,879

11. Asset Retirement Obligati36

11. Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	December 31, 2016 2015 Asset retirement obligations, at the beginning of the period $ 1,985,864 $ 1,866,770 New asset retirement obligations and adjustments — 49 Liabilities settled (70,969 ) (92,330 ) Accretion expense 112,744 211,375 2,027,639 1,985,864 Less: asset retirement obligations, current portion (17,510 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 2,010,129 $ 1,947,220

14. Concentration of Risk (Tabl

14. Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2016
Concentration Of Risk Tables
Percentages of all refined petroleum products sales to total sales	Years Ended December 31, 2016 2015 LPG mix $ 714,285 0.4 % $ 1,253,826 0.6 % Naphtha 35,544,394 21.5 % 48,410,300 22.0 % Jet fuel 55,459,227 33.5 % 67,085,046 30.4 % HOBM 35,924,098 21.8 % 46,936,751 21.3 % Reduced Crude 3,791,919 2.3 % 3,838,273 1.7 % AGO 33,979,855 20.5 % 52,914,392 24.0 % $ 165,413,778 100.0 % $ 220,438,588 100.0 %

15. Leases (Tables)

15. Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Future minimum lease payments	Years Ending December 31, 2017 $ 128,852

16. Income Taxes (Tables)

16. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Years Ended December 31, 2016 2015 Current: Federal $ — $ (111,566 ) State — (169,867 ) Deferred: Federal (3,607,237 ) (2,152,869 ) State — — $ (3,607,237 ) $ (2,434,302 )
Effective tax rate	2016 2015 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 0.00 % 1.64 % Federal tax 0.00 % 0.01 % Change in valuation allowance (63.66 )% 0.00 % (29.66 )% 35.65 %
NOL carryforwards	Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total Balance at December 31, 2014 $ 10,766,912 $ 12,145,789 $ 22,912,701 Net operating loss carryforwards utilized (1,152,463 ) (2,528,848 ) (3,681,311 ) — 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
Deferred tax assets and deferred tax liabilities	December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 13,550,338 $ 8,815,794 Start-up costs (Nixon Facility) 1,373,363 1,510,699 Asset retirement obligations liability/deferred revenue 717,751 717,723 Unrealized hedges — 62,356 AMT credit and other 266,522 302,086 Total deferred tax assets 15,907,974 11,408,658 Deferred tax liabilities: Fair market value adjustments — (46,116 ) Unrealized hedges — — Basis differences in property and equipment (5,895,943 ) (5,484,983 ) Total deferred tax liabilities (5,895,943 ) (5,531,099 ) 10,012,031 5,877,559 Valuation allowance (10,012,031 ) (2,270,322 ) Deferred tax assets, net $ — $ 3,607,237

17. Earnings Per Share (Tables)

17. Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings per share	Years Ended December 31, 2016 2015 Net income (loss) $ (15,767,448 ) $ 4,403,239 Basic and diluted income per share $ (1.51 ) $ 0.42 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,464,061 10,451,832

18. Fair Value Measurement (Tab

18. Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement at December 31, 2016 Using Financial assets (liabilities): Carrying Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs Commodity contracts $ — $ — $ — $ — Fair Value Measurement at December 31, 2015 Using Financial assets (liabilities): Carrying Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs Commodity contracts $ (183,400 ) $ (183,400 ) $ — $ —

19. Inventory Risk Management (

19. Inventory Risk Management (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional volume of outstanding contracts by type of instrument	Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2016 2017 2018 Refined petroleum products and crude oil - net short positions — — —
Fair value amounts of derivative instruments	Fair Value December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets $ — $ (183,400 )
Effect of derivative instruments	Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2016 2015 Commodity contracts Cost of refined products sold $ (2,445,898 ) $ 3,730,613

3. Significant Accounting Pol43

3. Significant Accounting Policies (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Cash and cash equivalents	$ 1,152,628	$ 1,853,875
Restricted cash	3,347,835	3,175,299
Restricted cash, noncurrent	1,582,305	15,616,478
Allowance for doubtful accounts	0	139,868
Impairment expense	968,684	0
Trade name	$ 303,346	$ 303,346

4. Business Segment Informati44

4. Business Segment Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenue from operations	$ 167,855,316	$ 221,732,620
Less: cost of operations	(177,790,949)	(206,665,215)
Other non-interest income	1,914,607	972,500
Adjusted EBITDA	(8,021,026)	16,039,905
Less: JMA Profit Share	(359,260)	(5,820,329)
Depletion, depreciation and amortization	(1,935,644)	(1,647,586)
Interest expense, net	(1,844,281)	(1,734,449)
Income (loss) before income taxes	(12,160,211)	6,837,541
Income tax expense	(3,607,237)	(2,434,302)
Net income (loss)		4,403,239
Capital expenditures	16,386,979	12,244,658
Identifiable assets	75,360,018	89,020,714
Segment Refinery Operations [Member]
Revenue from operations	167,780,326	221,586,156
Less: cost of operations	(175,340,816)	(205,403,355)
Other non-interest income	0	0
Adjusted EBITDA	(7,560,490)	16,182,801
Less: JMA Profit Share	(359,260)	(5,820,329)
EBITDA	(7,919,750)	10,362,472
Capital expenditures	16,386,979	12,244,658
Identifiable assets	74,236,629	82,605,078
Segment Pipeline Transportation [Member]
Revenue from operations	74,990	146,464
Less: cost of operations	(1,467,021)	(45,931)
Other non-interest income	1,914,607	312,500
Adjusted EBITDA	522,576	413,033
Less: JMA Profit Share	0	0
EBITDA	522,576	413,033
Capital expenditures	0	0
Identifiable assets	763,596	2,338,107
Corporate and Other
Revenue from operations	0	0
Less: cost of operations	(983,112)	(1,215,929)
Other non-interest income	0	660,000
Adjusted EBITDA	(983,112)	(555,929)
Less: JMA Profit Share	0	0
EBITDA	(983,112)	(555,929)
Net income (loss)		(15,767,448)
Capital expenditures	0	0
Identifiable assets	$ 359,793	$ 4,077,529

5. Prepaid Expenses and Other45

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Prepaid Expenses And Other Current Assets Details
Short-term tax bond	$ 505,000	$ 0
Prepaid exise taxes	292,338	0
Prepaid insurance	248,853	315,120
Prepaid related party operating expenses	0	624,570
Unrealized hedging gains	0	0
Prepaid Expenses, Net	$ 1,046,191	$ 939,690

6. Inventory (Details)

6. Inventory (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Jet fuel	$ 964,124	$ 309,850
Naphtha	533,580	5,007,576
HOBM	212,987	2,045,784
Chemicals	182,751	278,278
AGO	143,362	122,777
Crude oil and condensate	26,123	7,152
Propane	11,318	17,860
LPG mix	1,293	19,041
Inventories, Net	$ 2,075,538	$ 7,808,318

7. Property, Plant and Equipm47

7. Property, Plant and Equipment, Net (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment Net Details
Refinery and facilities	$ 50,814,309	$ 40,195,928
Pipelines and facilities	0	2,127,207
Onshore separation and handling facilities	0	325,435
Land	602,938	602,938
Other property and equipment	652,795	644,795
Property, Plant and Equipment, Gross	52,070,042	43,896,303
Less: Accumulated depletion, depreciation, and amortization	(6,685,244)	(6,234,161)
Property, Plant and Equipment less depreciation	45,384,798	37,662,142
Construction in Progress	16,939,665	11,179,670
Property, Plant and Equipment, Net	$ 62,324,463	$ 48,841,812

7. Property, Plant and Equipm48

7. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment Net Details Narrative
Interest Costs Capitalized	$ 2,108,298	$ 556,032

8. Related Party Transactions49

8. Related Party Transactions (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Unsettled reimbursements	$ 0	$ 624,570
Accounts payable, related party	369,600	300,000
Long-term debt, related party	5,314,690	0
Long-term debt, related party, current portion	(500,000)	0
Long-term debt, related party, net of current portion	4,814,690	0
Accrued interest, related party	243,556	0
Accrued interest, related party, current portion	(243,556)	0
Accrued interest, related party, net of current portion	0	0
LEH [Member]
Unsettled reimbursements	0	624,570
Long-term debt, related party	4,000,000	0
Accrued interest, related party	243,556	0
Ingleside [Member]
Accounts payable, related party	0	300,000
Long-term debt, related party	722,278	0
LMT [Member]
Accounts payable, related party	369,600	0
Johnathan Carroll [Member]
Long-term debt, related party	$ 592,412	$ 0

8. Related Party Transactions50

8. Related Party Transactions (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Refined petroleum product sales	$ 165,413,778	$ 220,438,588
Tank rental revenue	2,366,548	1,147,568
Pipeline operations	74,990	146,464
Total revenue from operations	167,855,316	221,732,620
Related party, cost of goods sold	369,600	0
Refinery operating expenses	$ 12,040,676	$ 11,683,658
Refinery operating expenses per bbl	$ 3.35	$ 2.80
Interest expenses under loan and guarantee, related party	$ 936,525	$ 320,123
LEH [Member]
Refined petroleum product sales	43,904,790	0
Tank rental revenue	1,125,000	0
Refinery operating expenses	$ 11,140,676	$ 11,333,658
Refinery operating expenses per bbl	$ 3.10	$ 2.71
Interest expenses under loan and guarantee, related party	$ 243,556	$ 0
Other Customers [Member]
Refined petroleum product sales	121,508,988	220,438,588
Tank rental revenue	1,241,548	1,147,568
Pipeline operations	74,990	146,464
LMT [Member]
Related party, cost of goods sold	369,600	0
Ingleside [Member]
Refinery operating expenses	$ 900,000	$ 350,000
Refinery operating expenses per bbl	$ .25	$ .09
Interest expenses under loan and guarantee, related party	$ 0	$ 0
Johnathan Carroll [Member]
Refinery operating expenses	$ 0	$ 0
Refinery operating expenses per bbl	$ 0	$ 0
Interest expenses under loan and guarantee, related party	$ 692,969	$ 320,123

8. Related Party Transactions51

8. Related Party Transactions (Details Narrative) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable, related party	$ 1,161,589	$ 0
LEH [Member]
Outstanding principal and interest	0
Accounts receivable, related party	1,161,589
Ingleside [Member]
Outstanding principal and interest	722,278
Johnathan Carroll [Member]
Outstanding principal and interest	$ 592,412

9. Accrued Expenses and Other52

9. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Accrued Expenses And Other Current Liabilities Details
Customer deposits	$ 450,000	$ 157,714
Unearned revenue	408,770	781,859
Other payable	189,719	103,024
Board of director fees payable	136,429	1,290,101
Insurance	67,783	0
Excise and income taxes payable	24,187	388,364
Property taxes	4,694	0
Genesis JMA Profit Share payable	0	86,429
Transportation and inspection	0	183,400
Accrued Expenses and Other Current Liabilities, Net	$ 1,281,582	$ 2,990,891

10. Long-Term Debt, Net (Detail

10. Long-Term Debt, Net (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 23,924,607	$ 24,643,081
Second Term Loan Due 2034	9,729,853	10,000,000
LEH Loan Agreement	4,000,000	0
Ingleside Note	722,278	0
Notre Dame Debt	1,300,000	1,300,000
Carroll Note	592,412	0
Term Loan Due 2017	184,994	924,969
Capital Leases	135,879	304,618
Total	40,590,023	37,172,668
Less: current portion of long-term debt	(32,212,336)	(1,934,932)
Less: unamortized debt issue costs	(2,262,997)	(2,391,482)
Long term debt	$ 1,300,000	$ 32,846,254

10. Long-Term Debt, Net (Deta54

10. Long-Term Debt, Net (Details 1) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Debt Issue Costs	$ 2,262,997	$ 2,391,482
Less: Accumulated amortization	(178,221)	(49,736)
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, 2016	Dec. 31, 2015
Interest payable	$ 2,015,139	$ 1,564,268
Less: Interest payable, current portion	(323,756)	(81,467)
Interest payable, noncurrent	1,691,383	1,482,801
Notre Dame Debt [Member]
Interest payable	1,691,383	1,482,801
LEH [Member]
Interest payable	243,556	0
Second Term Loan Due 2034 [Member]
Interest payable	44,984	39,193
First Term Loan Due 2034 [Member]
Interest payable	33,866	34,883
Capital Leases [Member]
Interest payable	1,165	2,612
Term Loan Due 2017 [Member]
Interest payable	$ 185	$ 4,779

10. Long-Term Debt, Net (Deta56

10. Long-Term Debt, Net (Details 3)	Dec. 31, 2016USD ($)
Long-term Debt Net Details 3
2,017	$ 34,475,333
2,018	6,114,690
2,019	0
2,020	0
2,021	0
Subsequent to 2021	0
Long Term Debt Payment, Net	$ 40,590,023

10. Long-Term Debt, Net (Deta57

10. Long-Term Debt, Net (Details 4) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Long-term Debt Net Details 4
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation	0	0
Capital lease obligation	$ 538,598	$ 538,598

10. Long-Term Debt, Net (Deta58

10. Long-Term Debt, Net (Details 5)	Dec. 31, 2016USD ($)
Long-term Debt Net Details 5
2,017	$ 138,310
Less: amount representing interest	(2,431)
Present value of minimum lease payments	$ 135,879

10. Long-Term Debt, Net (Deta59

10. Long-Term Debt, Net (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Amortization expense	$ 128,485	$ 544,607
Principal balance outstanding	1,300,000	32,846,254
Capital Leases	135,879	304,618
Term Loan Due 2034 [Member]
Guaranty fees	485,463	265,518
Second Term Loan Due 2034 [Member]
Guaranty fees	197,024	16,667
Term Loan Due 2017 [Member]
Guaranty fees	$ 10,483	$ 11,439

11. Asset Retirement Obligati60

11. Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations Details
Asset retirement obligations, at the beginning of the period	$ 1,985,864	$ 1,866,770
New asset retirement obligations and adjustments	0	49
Liabilities settled	(70,969)	(92,330)
Accretion expense	112,744	211,375
Total	2,027,639	1,985,864
Less: current portion of asset retirement obligations	(17,510)	(38,644)
Long-term asset retirement obligations, at the end of the period	$ 2,010,129	$ 1,947,220

11. Asset Retirement Obligati61

11. Asset Retirement Obligations (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations Details Narrative
Liabilities settled recognized	$ 70,969	$ 92,330
Abandonment expense	$ 0	$ 0

12. Impairment (Details Narrati

12. Impairment (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Impairment Details Narrative
Impairment expense	$ 968,684	$ 0

13. Treasury Stock (Details Nar

13. Treasury Stock (Details Narrative) - shares	Dec. 31, 2016	Dec. 31, 2015
Treasury Stock Details Narrative
Treasury stock	150,000	150,000

14. Concentration of Risk (Deta

14. Concentration of Risk (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Total refined petroleum product sales	$ 165,413,778	$ 220,438,588
Concentration Risk	100.00%	100.00%
LPG mix [Member]
Total refined petroleum product sales	$ 714,285	$ 1,253,826
Concentration Risk	0.40%	0.60%
Naphtha
Total refined petroleum product sales	$ 35,544,394	$ 48,410,300
Concentration Risk	21.50%	22.00%
Jet Fuel [Member]
Total refined petroleum product sales	$ 55,459,227	$ 67,085,046
Concentration Risk	33.50%	30.40%
HOBM [Member]
Total refined petroleum product sales	$ 35,924,098	$ 46,936,751
Concentration Risk	21.80%	21.30%
Reduced crude [Member]
Total refined petroleum product sales	$ 3,791,919	$ 3,838,273
Concentration Risk	2.30%	1.70%
AGO [Member]
Total refined petroleum product sales	$ 33,979,855	$ 52,914,392
Concentration Risk	20.50%	24.00%

14. Concentration of Risk (De65

14. Concentration of Risk (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250,000	$ 250,000
Excess of the FDIC insurance limit	$ 5,372,689	$ 19,594,883
Sales Revenue [Member] | Four customers [Member]
Concentration Risk	67.00%
Sales Revenue [Member] | Three customers [Member]
Concentration Risk		56.00%
Sales Revenue [Member] | LEH [Member]
Concentration Risk	27.00%
Account receivable [Member] | Four customers [Member]
Accounts receivable	$ 1,600,000
Account receivable [Member] | Three customers [Member]
Accounts receivable		$ 3,000,000
Account receivable [Member] | LEH [Member]
Accounts receivable	$ 1,600,000

15. Leases (Details)

15. Leases (Details)	Dec. 31, 2016USD ($)
Leases Details 1
2,017	$ 128,852

15. Leases (Details Narrative)

15. Leases (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Leases Details Narrative
Rent expense	$ 142,604	$ 142,604

16. Income Taxes (Details)

16. Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ 0	$ (111,566)
State	0	(169,867)
Deferred:
Federal	(3,607,237)	(2,152,869)
State	0	0
Income tax benefit (expense)	$ (3,607,237)	$ (2,434,302)

16. Income Taxes (Details 1)

16. Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Leases Details 1 [Default Label]
Expected tax rate	34.00%	34.00%
Permanent differences	0.00%	0.00%
State tax	0.00%	1.64%
Federal tax	0.00%	0.01%
Change in valuation allowance	0.00%	0.00%
Expected tax rate Continuing Operations	34.00%	35.65%

16. Income Taxes (Details 2)

16. Income Taxes (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Balance	$ 19,231,390	$ 22,912,701
Net operating loss carryforward utilized	13,945,128	(3,681,311)
Balance	33,176,518	19,231,390
Pre-Ownership Change [Member]
Balance	9,614,449	10,766,912
Net operating loss carryforward utilized	0	(1,152,463)
Balance	9,614,449	9,614,449
Post-Ownership Change [Member]
Balance	9,616,941	236,564
Net operating loss carryforward utilized	13,945,128	(2,528,848)
Balance	$ 23,562,069	$ 9,616,941

16. Income Taxes (Details 3)

16. Income Taxes (Details 3) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 13,550,338	$ 8,815,794
Start-up costs (Nixon Facility)	1,373,363	1,510,699
Asset retirement obligations liability/deferred revenue	717,751	717,723
Unrealized hedges	0	62,356
AMT credit and other	266,522	302,086
Total deferred tax assets	15,907,974	11,408,658
Deferred tax liabilities:
Fair market value adjustments	0	(46,116)
Unrealized hedges	0	0
Basis differences in property and equipment	(5,895,943)	(5,484,983)
Total deferred tax liabilities	(5,895,943)	(5,531,099)
Deferred tax assets, net	10,012,031	5,877,559
Valuation allowance	(10,012,031)	(2,270,322)
Deferred tax assets, net	$ 0	$ 3,607,237

17. Earnings per share (Details

17. Earnings per share (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (15,767,448)	$ 4,403,239
Basic and diluted income (loss) per share	$ (1.51)	$ 0.42
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,464,061	10,451,832

18. Fair Value Measurement (Det

18. Fair Value Measurement (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Financial liabilties:
Commodity contracts	$ 0	$ (183,400)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
Financial liabilties:
Commodity contracts	0	(183,400)
Significant Other Observable Inputs (Level 2)
Financial liabilties:
Commodity contracts	0	0
Significant Unobservable Inputs (Level 3)
Financial liabilties:
Commodity contracts	$ 0	$ 0

18. Fair Value Measurement (D74

18. Fair Value Measurement (Details Narrative) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of long term debt and short-term notes payable	$ 40,590,023	$ 37,172,668

19. Inventory Risk Management75

19. Inventory Risk Management (Details) - Refined products - net short (long) positions	Dec. 31, 2016shares
Volume in Thousands of barrels
Notional Contract Volumes 2016	0
Notional Contract Volumes 2017	0
Notional Contract Volumes 2018	0

19. Inventory Risk Management76

19. Inventory Risk Management (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Inventory Risk Management Details 1
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 0	$ (183,400)
Cost of refined products sold	$ (2,445,898)	$ 3,730,613