Blue Dolphin Energy (BDCO) 10-Q 15 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 15, 2016
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-Q
Document Period End Date	Jun. 30, 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		10,464,715
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2,016

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 2,183,562	$ 1,853,875
Restricted cash	4,186,150	3,175,299
Accounts receivable, net	9,132,900	5,457,245
Prepaid expenses and other current assets	843,639	939,690
Deposits	260,965	395,414
Inventory	9,684,121	7,808,318
Total current assets	26,291,337	19,629,841
Total property and equipment, net	57,597,369	48,841,812
Restricted cash, noncurrent	7,953,623	15,616,478
Surety bonds	710,000	1,022,000
Trade name	303,346	303,346
Deferred tax assets, net	6,307,479	3,607,237
Total long-term assets	72,871,817	69,390,873
TOTAL ASSETS	99,163,154	89,020,714
CURRENT LIABILITIES
Accounts payable	32,433,145	14,882,714
Accounts payable, related party	861,963	300,000
Asset retirement obligations, current portion	26,399	38,644
Accrued expenses and other current liabilities	1,087,654	2,990,891
Interest payable, current portion	77,193	81,467
Long-term debt less unamortized debt issue costs, current portion	32,551,240	1,934,932
Total current liabilities	67,037,594	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,956,590	1,947,220
Deferred revenues and expenses	104,237	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,349,324	32,846,254
Long-term interest payable, net of current portion	1,586,522	1,482,801
Total long-term liabilities	4,996,673	36,401,360
TOTAL LIABILITIES	72,034,267	56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,614,715 and 10,603,802 shares issued at June 30, 2016 and December 31, 2015, respectively)	106,148	106,038
Additional paid-in capital	36,788,628	36,738,737
Accumulated deficit	(8,965,889)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	27,128,887	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 99,163,154	$ 89,020,714

Consolidated Balance Sheets (U3

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 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	10,614,715	10,603,802
Common stock, shares outstanding	10,614,715	10,603,802
Treasury stock, shares	150,000	150,000

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 41,402,286	$ 58,839,160	$ 72,595,423	$ 119,906,222
Tank rental revenue	615,487	286,892	906,974	573,784
Pipeline operations	24,687	35,562	52,339	73,957
Total revenue from operations	42,042,460	59,161,614	73,554,736	120,553,963
COST OF OPERATIONS
Cost of refined products sold	42,633,298	53,801,698	73,626,775	103,189,147
Refinery operating expenses	2,877,748	2,586,151	6,314,763	5,467,122
Joint Marketing Agreement profit share	97,527	938,661	(573,565)	3,377,298
Pipeline operating expenses	95,195	60,887	174,485	107,483
Lease operating expenses	8,455	14,098	23,107	21,414
General and administrative expenses	255,319	400,018	612,323	745,902
Depletion, depreciation and amortization	470,347	402,937	910,800	802,168
Recovery of bad debt			(139,868)
Accretion expense	28,186	52,720	56,372	105,935
Total cost of operations	46,466,075	58,257,170	81,005,192	113,816,469
Income (loss) from operations	(4,423,615)	904,444	(7,450,456)	6,737,494
OTHER INCOME (EXPENSE)
Easement, interest and other income	126,097	66,460	257,860	132,467
Interest and other expense	(399,559)	(732,296)	(819,466)	(940,371)
Total other expense	(273,462)	(665,836)	(561,606)	(807,904)
Income (loss) before income taxes	(4,697,077)	238,608	(8,012,062)	5,929,590
Income tax benefit (expense)	1,534,341	(100,729)	2,700,242	(2,090,347)
Net income (loss)	$ (3,162,736)	$ 137,879	$ (5,311,820)	$ 3,839,243
Income (loss) per common share:
Basic	$ (0.30)	$ 0.01	$ (0.51)	$ 0.37
Diluted	$ (0.30)	$ 0.01	$ (0.51)	$ 0.37
Weighted average number of common shares outstanding:
Basic	10,459,996	10,450,210	10,458,895	10,449,829
Diluted	10,459,996	10,450,210	10,458,895	10,449,829

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
OPERATING ACTIVITIES
Net income (loss)	$ (5,311,820)	$ 3,839,243
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	910,800	802,168
Unrealized loss (gain) on derivatives	(385,350)	467,000
Deferred tax expense (benefit)	(2,700,242)	1,892,551
Amortization of debt issue costs	64,243	500,566
Accretion expense	56,372	105,935
Common stock issued for services	50,000	19,999
Recovery of bad debt	(139,868)
Changes in operating assets and liabilities
Accounts receivable	(3,535,787)	1,195,096
Prepaid expenses and other current assets	298,001	349,015
Deposits and other assets	446,449	(1,385,751)
Inventory	(1,875,803)	(643,882)
Accounts payable, accrued expenses and other liabilities	13,256,568	(1,093,032)
Accounts payable, related party	561,963	(1,174,168)
Net cash provided by operating activities	1,695,526	4,874,740
INVESTING ACTIVITIES
Capital expenditures	(7,072,978)	(5,800,487)
Change in restricted cash for investing activities	7,662,855	(13,500,000)
Net cash provide by (used in) investing activities	589,877	(19,300,487)
FINANCING ACTIVITIES
Proceeds from issuance of debt		28,000,000
Payments on long-term debt	(944,865)	(9,071,159)
Change in restricted cash for financing activities	(1,010,851)	(3,287,813)
Net cash (used in) provided by financing activities	(1,955,716)	15,641,028
Net increase in cash and cash equivalents	329,687	1,215,281
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	2,183,562	2,508,514
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	2,593,379	459,007
Interest paid	988,979	353,833
Income taxes paid		$ 95,000

1. Organization

1. Organization	6 Months Ended
	Jun. 30, 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 II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Owned and Leased Assets” in our Form 10-K for the fiscal year ended December 31, 2015 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding our operating subsidiaries. References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires. Operating Risks As of June 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank(“Sovereign”). As a result of these covenant defaults, Sovereign could elect to declare the amounts owed under these loan agreements to be immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, or exercise any other rights and remedies available. Accordingly, $31,824,613 of debt under these loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016. (See “Note (9) Long-Term Debt, Net” and “Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.) In addition to the Joint Marketing Agreement, we are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice. An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contractual dispute with Genesis.) Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive, and other factors that are beyond our control. There can be no assurance that our business and operational strategy will achieve anticipated outcomes. If our strategy is not successful, our working capital requirements are not funded through Operations Payments or our profit share under the Joint Marketing Agreement or certain advances from LEH, or Sovereign exercises remedies available under the loan agreements for covenant violations, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

2. Basis of Presentation

2. Basis of Presentation	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading. The consolidated balance sheet as of December 31, 2015 has been derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report. Operating results for the three and six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2016, or for any other period.

3. Significant Accounting Polic

3. Significant Accounting Policies	6 Months Ended
	Jun. 30, 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 effectively 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 (17) Fair Value Measurement” and “Note (18) 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 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 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 of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. The guidance 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 (15) Income Taxes” for further information related to income taxes.) Impairment or Disposal of Long-Lived Assets Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. (See “Note (11) Asset Retirement Obligations” for additional information related to our AROs.) Computation of Earnings Per Share The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. (See “Note (16) Earnings Per Share” for additional information related to EPS.) Stock-Based Compensation Treasury Stock New Pronouncements Adopted ASU 2015-17,Income Taxes (Topic 740) ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs New Pronouncements Issued But Not Yet Effective 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 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). ASU 2014-09,Revenue from Contracts with Customers (Topic 606) • August 2015 – ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, • March 2016– ASU 2016-08,Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), • April 2016– ASU 2016-10 Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing • May 2016 – 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) Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, and , • May 2016 – ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and 2016-12, 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 effective until after June 30, 2016 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	6 Months Ended
	Jun. 30, 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: Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 42,017,773 $ 24,687 $ - $ 42,042,460 $ 59,126,052 $ 35,562 $ - $ 59,161,614 Less: cost of operations (1) (45,534,109 ) (131,836 ) (232,256 ) (45,898,201 ) (56,504,401 ) (127,704 ) (283,467 ) (56,915,572 ) Other non-interest income (2) - 125,000 - 125,000 - 62,500 - 62,500 Adjusted EBITDA (3) (3,516,336 ) 17,851 (232,256 ) (3,730,741 ) 2,621,651 (29,642 ) (283,467 ) 2,308,542 Less: JMA Profit Share (4) (97,527 ) - - (97,527 ) (938,661 ) - - (938,661 ) EBITDA (3) $ (3,613,863 ) $ 17,851 $ (232,256 ) $ 1,682,990 $ (29,642 ) $ (283,467 ) Depletion, depreciation, and amortization (470,347 ) (402,937 ) Interest expense, net (398,462 ) (728,336 ) Income (loss) before income taxes (4,697,077 ) 238,608 Income tax benefit (expense) 1,534,341 (100,729 ) Net income (loss) $ (3,162,736 ) $ 137,879 Capital expenditures $ 3,433,333 $ - $ - $ 3,433,333 $ 4,967,579 $ - $ - $ 4,967,579 Identifiable assets (5) $ 93,402,963 $ 1,867,687 $ 3,892,504 $ 99,163,154 $ 73,643,964 $ 2,788,381 $ 4,046,157 $ 80,478,502 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) (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. Business segment information for the periods indicated (and as of the dates indicated), was as follows: Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 73,502,397 $ 52,339 $ - $ 73,554,736 $ 120,480,006 $ 73,957 $ - $ 120,553,963 Less: cost of operations (1) (79,956,962 ) (253,964 ) (457,031 ) (80,667,957 ) (108,763,871 ) (181,616 ) (691,515 ) (109,637,002 ) Other non-interest income (2) - 255,665 - 255,665 - 125,000 - 125,000 Adjusted EBITDA (3) (6,454,565 ) 54,040 (457,031 ) (6,857,556 ) 11,716,135 17,341 (691,515 ) 11,041,961 Less: JMA Profit Share (4) 573,565 - - 573,565 (3,377,298 ) - - (3,377,298 ) EBITDA (3) $ (5,881,000 ) $ 54,040 $ (457,031 ) $ 8,338,837 $ 17,341 $ (691,515 ) Depleton, depreciation and amortization (910,800 ) (802,168 ) Interest expense, net (817,271 ) (932,905 ) Income (loss) before income taxes (8,012,062 ) 5,929,590 Income tax benefit (expense) 2,700,242 (2,090,347 ) Net income (loss) $ (5,311,820 ) $ 3,839,243 Capital expenditures $ 7,072,978 $ - $ - $ 7,072,978 $ 6,259,494 $ - $ - $ 6,259,494 Identifiable assets (5) $ 93,402,963 $ 1,867,687 $ 3,892,504 $ 99,163,154 $ 73,643,964 $ 2,788,381 $ 4,046,157 $ 80,478,502 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) (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	6 Months Ended
	Jun. 30, 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: June 30, December 31, 2016 2015 Prepaid related party operating expenses $ 402,671 $ 624,570 Prepaid insurance 231,518 315,120 Unrealized hedging gains 201,950 - Prepaid listing fees 7,500 - $ 843,639 $ 939,690

6. Inventory

6. Inventory	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 HOBM $ 6,382,469 $ 5,007,576 Jet fuel 1,438,134 2,045,784 Crude oil and condensate 936,301 19,041 Naphtha 333,627 309,850 AGO 288,707 278,278 Chemicals 282,562 122,777 Propane 17,299 17,860 LPG mix 5,022 7,152 $ 9,684,121 $ 7,808,318

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	6 Months Ended
	Jun. 30, 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: June 30, December 31, 2016 2015 Refinery and facilities $ 47,660,502 $ 40,195,928 Pipelines and facilities 2,127,207 2,127,207 Onshore separation and handling facilities 325,435 325,435 Land 602,938 602,938 Other property and equipment 652,795 644,795 51,368,877 43,896,303 Less: Accumulated depletion, depreciation, and amortization (7,144,961 ) (6,234,161 ) 44,223,916 37,662,142 Construction in progress 13,373,453 11,179,670 $ 57,597,369 $ 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 $1,363,536 and $556,032 as of June 30, 2016 and December 31, 2015, respectively.

8. Accounts Payable, Related Pa

8. Accounts Payable, Related Party	6 Months Ended
	Jun. 30, 2016
Payables and Accruals [Abstract]
Accounts Payable, Related Party	Accounts payable, related party as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Ingleside $ 554,389 $ 300,000 Jonathan Carroll 307,574 - $ 861,963 $ 300,000 Accounts payable, related party correspond to the following: Ingleside Crude, LLC (“Ingleside”) For the three months ended June 30, 2016 and 2015, fees to Ingleside totaled $450,000(approximately $0.63 per bbl of throughput) and $0, respectively. For the six months ended June 30, 2016 and 2015, fees to Ingleside totaled $725,000(approximately $0.38 per bbl of throughput) and $0, respectively. LEH Operating Agreement • Reimbursements – • Fees – Product Sales Agreement Terminal Services Agreement Jonathan Carroll We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions.

9. Long-Term Debt, Net

9. Long-Term Debt, Net	6 Months Ended
	Jun. 30, 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 as of December 31, 2015 has been 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 represents the outstanding principal and interest of long-term debt less associated debt issue costs, as of the dates indicated consisted of the following: June 30, 2016 December 31, 2015 Debt Issue Long-Term Debt Issue Long-Term Principal Costs Debt, Net Principal Costs Debt, Net First Term Loan Due 2034 $ 24,289,190 $ (1,579,769 ) $ 22,709,421 $ 24,643,081 $ (1,623,810 ) $ 23,019,271 Second Term Loan Due 2034 9,862,663 (747,471 ) 9,115,192 10,000,000 (767,672 ) 9,232,328 Notre Dame Debt 1,300,000 - 1,300,000 1,300,000 - 1,300,000 Term Loan Due 2017 554,982 - 554,982 924,969 - 924,969 Capital Leases 220,969 - 220,969 304,618 - 304,618 $ 36,227,804 $ (2,327,240 ) $ 33,900,564 $ 37,172,668 $ (2,391,482 ) $ 34,781,186 Less: Long-term debt less unamortized debt issue costs, current portion (32,551,240 ) (1,934,932 ) $ 1,349,324 $ 32,846,254 Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Notre Dame Debt $ 1,586,522 $ 1,482,801 Second Term Loan Due 2034 42,610 39,193 First Term Loan Due 2034 32,226 34,883 Capital Leases 1,894 2,612 Term Loan Due 2017 463 4,779 1,663,715 1,564,268 Less: Interest payable, current portion (77,193 ) (81,467 ) $ 1,586,522 $ 1,482,801 First Term Loan Due 2034 As of June 30, 2016, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants under the First Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 was classified within the current portion of long-term debt on our consolidated balance sheet as of June 30, 2016. (See “Note (1) Organization – Operating Risks” and “Note (20) 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 repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LE entered into 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 First Term Loan Due 2034. For the three months ended June 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $121,739 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $244,372 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034. (See “Note (8) Accounts Payable, Related Party” for additional disclosures related to LEH and Jonathan Carroll.) 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 credit facilities of this type. Second Term Loan Due 2034 As of June 30, 2016, LRM was in violation of the debt service coverage ratio, the current ratio, and the debt to net worth ratio financial covenants under the Second Term Loan Due 2034. Accordingly, the Second Term Loan Due 2034 was classified within the current portion of long-term debt on our consolidated balance sheets. (See “Note (1) Organization – Operating Risks” and “Note (20) 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 into 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 three months ended June 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,420 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $99,168 and $0, 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) Accounts Payable, Related Party” 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 credit facilities of this type. 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. Term Loan Due 2017 As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered into 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 Term Loan Due 2017. For the three months ended June 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $3,083 and $0, respectively. For the six months ended June 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $7,091 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. 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) Accounts Payable, Related Party” 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: June 30, December 31, 2016 2015 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598

10. Accrued Expenses and Other

10. Accrued Expenses and Other Current Liabilities	6 Months Ended
	Jun. 30, 2016
Disclosure Text Block Supplement [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Unearned revenue $ 332,055 $ 781,859 Excise and income taxes payable 273,735 1,290,101 Other payable 152,914 157,714 Transportation and inspection 123,337 - Board of director fees payable 101,429 86,429 Property taxes 61,178 - Insurance 25,756 103,024 Inspection fees 17,250 - Genesis JMA Profit Share payable - 388,364 Unrealized hedging loss - 183,400 $ 1,087,654 $ 2,990,891

11. Asset Retirement Obligation

11. Asset Retirement Obligations	6 Months Ended
	Jun. 30, 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: June 30, 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 (59,247 ) (92,330 ) Accretion expense 56,372 211,375 1,982,989 1,985,864 Less: asset retirement obligations, current portion (26,399 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 1,956,590 $ 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. As of June 30, 2016 and December 31, 2015, we recognized $59,247 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 three months ended June 30, 2016 and 2015, we recognized $0 in abandonment expense. For the six months ended June 30, 2016 and 2015, we recognized $0 in abandonment expense.

12. Treasury Stock

12. Treasury Stock	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Treasury Stock	As of June 30, 2016 and December 31, 2015, we had 150,000 shares of treasury stock.

13. Concentration of Risk

13. Concentration of Risk	6 Months Ended
	Jun. 30, 2016
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier (See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” for a summary of the Crude Supply Agreement and a discussion of the current contractual dispute with Genesis.) Significant Customers For the six months ended June 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum products sales. These 4 customers represented approximately $6.2 million in accounts receivable as of June 30, 2016. For the six months ended June 30, 2015, we had 3 customers that accounted for approximately 58% of our refined petroleum products sales. These 3 customers represented approximately $3.2 million in accounts receivable as of June 30, 2015. Refined Petroleum Product Sales Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 LPG mix $ 133,757 0.3 % $ 234,184 0.4 % $ 384,304 0.8 % $ 291,492 0.2 % Naphtha 7,287,804 17.6 % 13,413,484 22.7 % 16,313,325 28.9 % 26,829,683 22.4 % Jet fuel 17,539,473 42.4 % 17,411,470 29.6 % 26,045,786 27.3 % 33,930,973 28.3 % HOBM 7,889,499 19.1 % 13,622,360 23.2 % 11,052,994 10.1 % 31,031,439 25.9 % Reduced Crude 546,112 1.3 % - 0.0 % 3,791,919 10.4 % - 0.0 % AGO 8,005,641 19.3 % 14,157,662 24.1 % 15,007,095 22.5 % 27,822,635 23.2 % $ 41,402,286 100.0 % $ 58,839,160 100.0 % $ 72,595,423 100.0 % $ 119,906,222 100.0 %

14. Leases

14. Leases	6 Months Ended
	Jun. 30, 2016
Leases, Operating [Abstract]
Leases	Our company headquarters is located 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 three months ended June 30, 2016 and 2015, rent expense totaled $29,857 and $57,060, respectively. For the six months ended June 30, 2016 and 2015, rent expense totaled $59,715 and $82,889, respectively.

15. Income Taxes

15. Income Taxes	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Benefit (Expense) Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Current: Federal $ - $ 14,038 $ - $ (85,242 ) State - (29,701 ) - (112,554 ) Deferred: Federal 1,534,341 (85,066 ) 2,653,721 (1,892,551 ) $ 1,534,341 $ (100,729 ) $ 2,653,721 $ (2,090,347 ) 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 margin rather than on its net income, certain aspects of TMT make it similar to an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. 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 as a result 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 - 5,871,350 5,871,350 Balance at March 31, 2016 $ 9,614,449 $ 15,488,291 $ 25,102,740 Net operating losses - 4,230,763 4,230,763 Balance at June 30, 2016 $ 9,614,449 $ 19,719,054 $ 29,333,503 Deferred Tax Assets and Liabilities June 30, December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 12,243,743 $ 8,815,794 Start-up costs (Nixon Facility) 1,442,032 1,510,699 Asset retirement obligations liability/deferred revenue 709,657 717,723 Unrealized hedges - 62,356 AMT credit and other 275,857 302,086 Total deferred tax assets 14,671,289 11,408,658 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (68,663 ) - Basis differences in property and equipment (5,978,709 ) (5,484,983 ) Total deferred tax liabilities (6,093,488 ) (5,531,099 ) 8,577,801 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) Deferred tax assets, net $ 6,307,479 $ 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 three and six months ended June 30, 2016 and 2015. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2012, or after and by the state of Texas for tax years ending December 31, 2011, or after. We believe there are no uncertain tax positions for both federal and state income taxes.

16. Earnings Per Share

16. Earnings Per Share	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings Per Share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Net income (loss) $ (3,162,736 ) $ 137,879 $ (5,311,820 ) $ 3,839,243 Basic and diluted income per share $ (0.30 ) $ 0.01 $ (0.51 ) $ 0.37 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,459,996 10,450,210 10,458,895 10,444,829 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three and six months ended June 30, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

17. Fair Value Measurement

17. Fair Value Measurement	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	The purchase and sale of financial instruments may be executed for the purpose of economically hedging commodity price risks associated with our refined petroleum products and the purchase of crude oil and condensate. When executed these financial instruments are direct contractual obligations of our crude supplier and not us. However, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded 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 executed on our behalf 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 as of June 30, 2016 and December 31, 2015 due to their short-term maturities. The fair value of our long-term debt, net including the current portion as of June 30, 2016 and December 31, 2015 was $36,227,804 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 as of June 30, 2016 and December 31, 2015 and the basis for the measurement: Fair Value Measurement at June 30, 2016 Using Financial assets (liabilities): Carrying Value at June 30, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Significant Commodity contracts $ 201,950 $ 201,950 $ - $ - 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 Significant 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.

18. Inventory Risk Management

18. Inventory Risk Management	6 Months Ended
	Jun. 30, 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 the purpose of 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. As of June 30, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered into 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 330,000 - - The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of June 30, 2016 and December 31, 2015: Fair Value June 30, December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ 201,950 $ (183,400 ) The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and six months ended June 30, 2016 and 2015: Loss Recognized Three Months Ended June 30, Six Months Ended June 30, Derivatives Statements of Operations Location 2016 2015 2016 2015 Commodity contracts Cost of refined products sold $ (3,852,100 ) $ (1,370,293 ) $ (3,359,572 ) $ (442,709 )

19. Commitments and Contingenci

19. Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Operating Agreement Genesis Agreements Crude Supply Agreement Joint Marketing Agreement - We are entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month. In addition, we are 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. If Gross Profits are insufficient to cover Operations Payments, then GEL may: (i) reduce Operations Payments by an amount representing the difference between the Operations Payments and the Gross Profits for such monthly period, or (ii) provide the Operations Payments with such Operations Payments being considered deficit amounts owing to GEL. If Gross Profits are negative, then we are not entitled to receive Operations Payments and GEL may recoup any losses sustained by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated; and - GEL is 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 is entitled to receive 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share, and we are entitled to receive 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for a calendar month is payable to GEL and us in the following manner: (i) GEL is entitled to receive 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we are 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 as the “Joint Marketing Agreement Profit Share” or the “JMA Profit Share”. The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. The Joint Marketing Agreement had an initial term of three years expiring in August 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice. 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 (9) Long-Term Debt, Net” for further discussion related to the First Term Loan Due 2034.) Genesis Contractual Dispute FLNG Master Easement Agreement Supplemental Pipeline Bonds In August 2015, we received a letter from the BOEM requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In light of the NTL, we are awaiting further direction from the BOEM to address financial assurance requirements. As of June 30, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. 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 Nixon Facility Expansion e Legal Matters Genesis Contractual 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 customer. 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 intends to defend 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 related to: (i) failure to provide crude oil and condensate at cost as defined in the Crude Supply Agreement, and (ii) significant under delivery of crude oil and condensate, resulting in significant refinery downtime and a significant decrease in refinery throughput,refinery production, and refined petroleum product sales for the three and six months ended June 30, 2016. With regard to the Petition, the next hearing date and a trial date have been set for August 22, 2016 and December 5, 2016, respectively, although the parties may elect arbitration. With respect to the Arbitration, a hearing date has not yet been set. We do not expect the temporary injunction issued by the court to have a material effect on our results of operations or financial condition. However, we are unable to predict the outcome of these proceedings or their ultimate impact, if any, on our business, financial condition or results of operations and, accordingly, have not recorded a liability on our consolidated balance sheet as of June 30, 2016. Other Legal Matters Health, Safety and Environmental Matters

20. Subsequent Events

20. Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	BDPL Credit Facility Financial Covenant Defaults

3. Significant Accounting Pol26

3. Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable and 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 effectively 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 (17) Fair Value Measurement” and “Note (18) 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 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
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 of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. The guidance 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 (15) 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 (16) 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 2015-17,Income Taxes (Topic 740) ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs
New Pronouncements Issued but Not Yet Effective	New Pronouncements Issued But Not Yet Effective 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 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). ASU 2014-09,Revenue from Contracts with Customers (Topic 606) • August 2015 – ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, • March 2016– ASU 2016-08,Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), • April 2016– ASU 2016-10 Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing • May 2016 – 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) Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, and , • May 2016 – ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and 2016-12, 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 effective until after June 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.
Reclassification	Reclassification

4. Business Segment Informati27

4. Business Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Business segment reporting	Business segment information for the periods indicated (and as of the dates indicated), was as follows: Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 42,017,773 $ 24,687 $ - $ 42,042,460 $ 59,126,052 $ 35,562 $ - $ 59,161,614 Less: cost of operations (1) (45,534,109 ) (131,836 ) (232,256 ) (45,898,201 ) (56,504,401 ) (127,704 ) (283,467 ) (56,915,572 ) Other non-interest income (2) - 125,000 - 125,000 - 62,500 - 62,500 Adjusted EBITDA (3) (3,516,336 ) 17,851 (232,256 ) (3,730,741 ) 2,621,651 (29,642 ) (283,467 ) 2,308,542 Less: JMA Profit Share (4) (97,527 ) - - (97,527 ) (938,661 ) - - (938,661 ) EBITDA (3) $ (3,613,863 ) $ 17,851 $ (232,256 ) $ 1,682,990 $ (29,642 ) $ (283,467 ) Depletion, depreciation, and amortization (470,347 ) (402,937 ) Interest expense, net (398,462 ) (728,336 ) Income (loss) before income taxes (4,697,077 ) 238,608 Income tax benefit (expense) 1,534,341 (100,729 ) Net income (loss) $ (3,162,736 ) $ 137,879 Capital expenditures $ 3,433,333 $ - $ - $ 3,433,333 $ 4,967,579 $ - $ - $ 4,967,579 Identifiable assets (5) $ 93,402,963 $ 1,867,687 $ 3,892,504 $ 99,163,154 $ 73,643,964 $ 2,788,381 $ 4,046,157 $ 80,478,502 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) (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. Business segment information for the periods indicated (and as of the dates indicated), was as follows: Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 73,502,397 $ 52,339 $ - $ 73,554,736 $ 120,480,006 $ 73,957 $ - $ 120,553,963 Less: cost of operations (1) (79,956,962 ) (253,964 ) (457,031 ) (80,667,957 ) (108,763,871 ) (181,616 ) (691,515 ) (109,637,002 ) Other non-interest income (2) - 255,665 - 255,665 - 125,000 - 125,000 Adjusted EBITDA (3) (6,454,565 ) 54,040 (457,031 ) (6,857,556 ) 11,716,135 17,341 (691,515 ) 11,041,961 Less: JMA Profit Share (4) 573,565 - - 573,565 (3,377,298 ) - - (3,377,298 ) EBITDA (3) $ (5,881,000 ) $ 54,040 $ (457,031 ) $ 8,338,837 $ 17,341 $ (691,515 ) Depleton, depreciation and amortization (910,800 ) (802,168 ) Interest expense, net (817,271 ) (932,905 ) Income (loss) before income taxes (8,012,062 ) 5,929,590 Income tax benefit (expense) 2,700,242 (2,090,347 ) Net income (loss) $ (5,311,820 ) $ 3,839,243 Capital expenditures $ 7,072,978 $ - $ - $ 7,072,978 $ 6,259,494 $ - $ - $ 6,259,494 Identifiable assets (5) $ 93,402,963 $ 1,867,687 $ 3,892,504 $ 99,163,154 $ 73,643,964 $ 2,788,381 $ 4,046,157 $ 80,478,502 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.) (3) Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA. (4) The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.) (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 Other28

5. Prepaid Expenses and Other Current Assets (Tables)	6 Months Ended
	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid balances	Prepaid expenses and other current assets as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Prepaid related party operating expenses $ 402,671 $ 624,570 Prepaid insurance 231,518 315,120 Unrealized hedging gains 201,950 - Prepaid listing fees 7,500 - $ 843,639 $ 939,690

6. Inventory (Tables)

6. Inventory (Tables)	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 HOBM $ 6,382,469 $ 5,007,576 Jet fuel 1,438,134 2,045,784 Crude oil and condensate 936,301 19,041 Naphtha 333,627 309,850 AGO 288,707 278,278 Chemicals 282,562 122,777 Propane 17,299 17,860 LPG mix 5,022 7,152 $ 9,684,121 $ 7,808,318

7. Property, Plant and Equipm30

7. Property, Plant and Equipment, Net (Tables)	6 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Property and equipment	Property, plant and equipment, net, as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Refinery and facilities $ 47,660,502 $ 40,195,928 Pipelines and facilities 2,127,207 2,127,207 Onshore separation and handling facilities 325,435 325,435 Land 602,938 602,938 Other property and equipment 652,795 644,795 51,368,877 43,896,303 Less: Accumulated depletion, depreciation, and amortization (7,144,961 ) (6,234,161 ) 44,223,916 37,662,142 Construction in progress 13,373,453 11,179,670 $ 57,597,369 $ 48,841,812

8. Accounts Payable, Related 31

8. Accounts Payable, Related Party (Tables)	6 Months Ended
	Jun. 30, 2016
Accounts Payable Related Party Tables
Accounts Payable, Related Party	Accounts payable, related party as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Ingleside $ 554,389 $ 300,000 Jonathan Carroll 307,574 - $ 861,963 $ 300,000

9. Long-Term Debt, Net (Tables)

9. Long-Term Debt, Net (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long Term Debt	Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, as of the dates indicated consisted of the following: June 30, 2016 December 31, 2015 Debt Issue Long-Term Debt Issue Long-Term Principal Costs Debt, Net Principal Costs Debt, Net First Term Loan Due 2034 $ 24,289,190 $ (1,579,769 ) $ 22,709,421 $ 24,643,081 $ (1,623,810 ) $ 23,019,271 Second Term Loan Due 2034 9,862,663 (747,471 ) 9,115,192 10,000,000 (767,672 ) 9,232,328 Notre Dame Debt 1,300,000 - 1,300,000 1,300,000 - 1,300,000 Term Loan Due 2017 554,982 - 554,982 924,969 - 924,969 Capital Leases 220,969 - 220,969 304,618 - 304,618 $ 36,227,804 $ (2,327,240 ) $ 33,900,564 $ 37,172,668 $ (2,391,482 ) $ 34,781,186 Less: Long-term debt less unamortized debt issue costs, current portion (32,551,240 ) (1,934,932 ) $ 1,349,324 $ 32,846,254
Accrued interest related to our long-term debt, net	Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Notre Dame Debt $ 1,586,522 $ 1,482,801 Second Term Loan Due 2034 42,610 39,193 First Term Loan Due 2034 32,226 34,883 Capital Leases 1,894 2,612 Term Loan Due 2017 463 4,779 1,663,715 1,564,268 Less: Interest payable, current portion (77,193 ) (81,467 ) $ 1,586,522 $ 1,482,801
Schedule of summary of equipment held under long-term capital leases	A summary of equipment held under long-term capital leases as of the dates indicated follows: June 30, December 31, 2016 2015 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598

10. Accrued Expenses and Othe33

10. Accrued Expenses and Other Current Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Disclosure Text Block Supplement [Abstract]
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities as of the dates indicated consisted of the following: June 30, December 31, 2016 2015 Unearned revenue $ 332,055 $ 781,859 Excise and income taxes payable 273,735 1,290,101 Other payable 152,914 157,714 Transportation and inspection 123,337 - Board of director fees payable 101,429 86,429 Property taxes 61,178 - Insurance 25,756 103,024 Inspection fees 17,250 - Genesis JMA Profit Share payable - 388,364 Unrealized hedging loss - 183,400 $ 1,087,654 $ 2,990,891

11. Asset Retirement Obligati34

11. Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Changes to our ARO liability for the periods indicated were as follows: June 30, 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 (59,247 ) (92,330 ) Accretion expense 56,372 211,375 1,982,989 1,985,864 Less: asset retirement obligations, current portion (26,399 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 1,956,590 $ 1,947,220

13. Concentration of Risk (Tabl

13. Concentration of Risk (Tables)	6 Months Ended
	Jun. 30, 2016
Risks and Uncertainties [Abstract]
Percentages of all refined petroleum products sales to total sales	Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following: Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 LPG mix $ 133,757 0.3 % $ 234,184 0.4 % $ 384,304 0.8 % $ 291,492 0.2 % Naphtha 7,287,804 17.6 % 13,413,484 22.7 % 16,313,325 28.9 % 26,829,683 22.4 % Jet fuel 17,539,473 42.4 % 17,411,470 29.6 % 26,045,786 27.3 % 33,930,973 28.3 % HOBM 7,889,499 19.1 % 13,622,360 23.2 % 11,052,994 10.1 % 31,031,439 25.9 % Reduced Crude 546,112 1.3 % - 0.0 % 3,791,919 10.4 % - 0.0 % AGO 8,005,641 19.3 % 14,157,662 24.1 % 15,007,095 22.5 % 27,822,635 23.2 % $ 41,402,286 100.0 % $ 58,839,160 100.0 % $ 72,595,423 100.0 % $ 119,906,222 100.0 %

15. Income Taxes (Tables)

15. Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Income Tax Benefit (Expense) Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Current: Federal $ - $ 14,038 $ - $ (85,242 ) State - (29,701 ) - (112,554 ) Deferred: Federal 1,534,341 (85,066 ) 2,653,721 (1,892,551 ) $ 1,534,341 $ (100,729 ) $ 2,653,721 $ (2,090,347 )
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 as a result 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 - 5,871,350 5,871,350 Balance at March 31, 2016 $ 9,614,449 $ 15,488,291 $ 25,102,740 Net operating losses - 4,230,763 4,230,763 Balance at June 30, 2016 $ 9,614,449 $ 19,719,054 $ 29,333,503
Deferred tax assets and deferred tax liabilities	Significant components of deferred tax assets and liabilities as of the dates indicated were as follow: June 30, December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 12,243,743 $ 8,815,794 Start-up costs (Nixon Facility) 1,442,032 1,510,699 Asset retirement obligations liability/deferred revenue 709,657 717,723 Unrealized hedges - 62,356 AMT credit and other 275,857 302,086 Total deferred tax assets 14,671,289 11,408,658 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (68,663 ) - Basis differences in property and equipment (5,978,709 ) (5,484,983 ) Total deferred tax liabilities (6,093,488 ) (5,531,099 ) 8,577,801 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) Deferred tax assets, net $ 6,307,479 $ 3,607,237

16. Earnings Per Share (Tables)

16. Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings per share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Net income (loss) $ (3,162,736 ) $ 137,879 $ (5,311,820 ) $ 3,839,243 Basic and diluted income per share $ (0.30 ) $ 0.01 $ (0.51 ) $ 0.37 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,459,996 10,450,210 10,458,895 10,444,829

17. Fair Value Measurement (Tab

17. Fair Value Measurement (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 and the basis for the measurement: Fair Value Measurement at June 30, 2016 Using Financial assets (liabilities): Carrying Value at June 30, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Significant Commodity contracts $ 201,950 $ 201,950 $ - $ - 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 Significant Commodity contracts $ (183,400 ) $ (183,400 ) $ - $ -

18. Inventory Risk Management (

18. Inventory Risk Management (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional volume of outstanding contracts by type of instrument	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 330,000 - -
Fair value amounts of derivative instruments	The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of June 30, 2016 and December 31, 2015: Fair Value June 30, December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ 201,950 $ (183,400 )
Effect of derivative instruments	The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and six months ended June 30, 2016 and 2015: Loss Recognized Three Months Ended June 30, Six Months Ended June 30, Derivatives Statements of Operations Location 2016 2015 2016 2015 Commodity contracts Cost of refined products sold $ (3,852,100 ) $ (1,370,293 ) $ (3,359,572 ) $ (442,709 )

1. Organization (Details Narrat

1. Organization (Details Narrative) - USD ($)	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and cash equivalents	$ 2,183,562	$ 1,853,875	$ 2,508,514	$ 1,293,233
Restricted cash (current portion)	4,186,150	3,175,299
Current assets	26,291,337	19,629,841
Current liabilities	67,037,594	$ 20,228,648
Working capital deficit current portion	40,746,257
Working capital deficit payment of Operations	$ 8,195,017

3. Significant Accounting Pol41

3. Significant Accounting Policies (Details Narrative) - USD ($)	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 2,183,562	$ 1,853,875	$ 2,508,514	$ 1,293,233
Restricted cash	12,139,773	18,791,777
Restricted cash (current portion)	4,186,150	3,175,299
Restricted cash, noncurrent	7,953,623	15,616,478
Allowance for doubtful accounts	0	139,868
Trade name	$ 303,346	303,346
Deferred tax assets		3,500,000
Debt issue costs		$ 2,400,000

4. Business Segment Informati42

4. Business Segment Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenue from operations	$ 42,042,460	$ 59,161,614	$ 73,554,736	$ 120,553,963
Income tax benefit (expense)	(1,534,341)	100,729	(2,700,242)	2,090,347
Net income (loss)	(3,162,736)	137,879	(5,311,820)	3,839,243
Refinery Operations [Member]
Revenue from operations	42,017,773	59,126,052	73,502,397	120,480,006
Less: cost of operations	(45,534,109)	(56,504,401)	(79,956,962)	(108,763,871)
Other non-interest income
Adjusted EBITDA	(3,516,336)	2,621,651	(6,454,565)	11,716,135
Less: JMA Profit Share	(97,527)	(938,661)	573,565	(3,377,298)
EBITDA	(3,613,863)	1,682,990	(5,881,000)	8,338,837
Capital expenditures	3,433,333	4,967,579	7,072,978	6,259,494
Identifiable assets	93,402,963	73,643,964	93,402,963	73,643,964
Pipeline Transportation [Member]
Revenue from operations	24,687	35,562	52,339	73,957
Less: cost of operations	(131,836)	(127,704)	(253,964)	(181,616)
Other non-interest income	125,000	62,500	255,665	125,000
Adjusted EBITDA	17,851	(29,642)	54,040	17,341
Less: JMA Profit Share
EBITDA	17,851	(29,642)	54,040	17,341
Capital expenditures
Identifiable assets	1,867,687	2,788,381	1,867,687	2,788,381
Corporate and Other [Member]
Revenue from operations
Less: cost of operations	(232,256)	(283,467)	(457,031)	(691,515)
Other non-interest income
Adjusted EBITDA	(232,256)	(283,467)	(457,031)	(691,515)
Less: JMA Profit Share
EBITDA	(232,256)	(283,467)	(457,031)	(691,515)
Capital expenditures
Identifiable assets	3,892,504	4,046,157	3,892,504	4,046,157
Total
Revenue from operations	42,042,460	59,161,614	73,554,736	120,553,963
Less: cost of operations	(45,898,201)	(56,915,572)	(80,667,957)	(109,637,002)
Other non-interest income	125,000	62,500	255,665	125,000
Adjusted EBITDA	(3,730,741)	2,308,542	(6,857,556)	11,041,961
Less: JMA Profit Share	(97,527)	(938,661)	573,565	(3,377,298)
Depletion, depreciation and amortization	(470,347)	(402,937)	(910,800)	(802,168)
Interest expense, net	(398,462)	(728,336)	(817,271)	(932,905)
Income (loss) before income taxes	(4,697,077)	238,608	(8,012,062)	5,929,590
Income tax benefit (expense)	1,534,341	(100,729)	2,700,242	(2,090,347)
Net income (loss)	(3,162,736)	137,879	(5,311,820)	3,839,243
Capital expenditures	3,433,333	4,967,579	7,072,978	6,259,494
Identifiable assets	$ 99,163,154	$ 80,478,502	$ 99,163,154	$ 80,478,502

5. Prepaid Expenses and Other43

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid related party operating expenses	$ 402,671	$ 624,570
Prepaid insurance	231,518	315,120
Unrealized hedging gains	201,950
Prepaid listing fees	7,500
Prepaid expenses, net	$ 843,639	$ 939,690

6. Inventory (Details)

6. Inventory (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
HOBM	$ 6,382,469	$ 5,007,576
Jet fuel	1,438,134	2,045,784
Crude oil and condensate	936,301	19,041
Naphtha	333,627	309,850
AGO	288,707	278,278
Chemicals	282,562	122,777
Propane	17,299	17,860
LPG mix	5,022	7,152
Inventories, net	$ 9,684,121	$ 7,808,318

7. Property, Plant and Equipm45

7. Property, Plant and Equipment, Net (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 47,660,502	$ 40,195,928
Pipelines and facilities	2,127,207	2,127,207
Onshore separation and handling facilities	325,435	325,435
Land	602,938	602,938
Other property and equipment	652,795	644,795
Property, Plant and Equipment, Gross	51,368,877	43,896,303
Less: Accumulated depletion, depreciation and amortization	7,144,961	(6,234,161)
Property, plant and equipment, gross	44,223,916	37,662,142
Construction in progress	13,373,453	11,179,670
Property, plant and equipment, net	$ 57,597,369	$ 48,841,812

8. Property, Plant and Equipmen

8. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 1,363,536	$ 556,032

8. Accounts Payable, Related 47

8. Accounts Payable, Related Party (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Accounts payable, related party	$ 861,963	$ 300,000
Ingleside [Member]
Accounts payable, related party	554,389	300,000
Jonathan Carroll [Member]
Accounts payable, related party	$ 307,574

8. Accounts Payable, Related 48

8. Accounts Payable, Related Party (Details Narrative) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Expense for service	$ 450,000	$ 0	$ 725,000	$ 0
Prepaid related party operating expenses	402,671		402,671		$ 624,570
Accounts payable, related party	861,963		861,963		$ 300,000
LEH [Member]
Expense for service	2,427,748	2,586,151	5,589,763	5,467,122
Sales to LEH totaled	8,912,074	0	8,912,074	0
Services Agreement Fees	$ 324,000	$ 0	$ 324,000	$ 0

9. Long-Term Debt, Net (Details

9. Long-Term Debt, Net (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Principal balance outstanding	$ 36,227,804	$ 37,172,668
Debt Issue Costs	(2,327,240)	(2,391,482)
Long-Term Debt, Net	33,900,564	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion	(32,551,240)	(1,934,932)
Long term debt	1,349,324	32,846,254
First Term Loan Due 2034 [Member]
Principal balance outstanding	24,289,190	24,643,081
Debt Issue Costs	(1,579,769)	(1,623,810)
Long-Term Debt, Net	22,709,421	23,019,271
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,862,663	10,000,000
Debt Issue Costs	(747,471)	(767,672)
Long-Term Debt, Net	9,115,192	9,232,328
Notre Dame Debt [Member]
Principal balance outstanding	1,300,000	1,300,000
Debt Issue Costs
Long-Term Debt, Net	1,300,000	1,300,000
Term Loan Due 2017 [Member]
Principal balance outstanding	554,982	924,969
Debt Issue Costs
Long-Term Debt, Net	554,982	924,969
Capital Leases [Member]
Principal balance outstanding	220,969	304,618
Debt Issue Costs
Long-Term Debt, Net	$ 220,969	$ 304,618

9. Long-Term Debt, Net (Detai50

9. Long-Term Debt, Net (Details 1) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notre Dame Debt	$ 1,586,522	$ 1,482,801
Second Term Loan Due 2034	42,610	39,193
First Term Loan Due 2034	32,226	34,883
Capital leases	1,894	2,612
Term Loan Due 2017	463	4,779
Total	1,663,715	1,564,268
Less: Interest payable, current portion	(77,193)	(81,467)
Long term debt	$ 1,586,522	$ 1,482,801

9. Long-Term Debt, Net (Detai51

9. Long-Term Debt, Net (Details 2) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation
Capital lease obligation	$ 538,598	$ 538,598

9. Long-Term Debt, Net (Detai52

9. Long-Term Debt, Net (Details Narrative) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Principal balance outstanding	$ 1,349,324		$ 1,349,324		$ 32,846,254
Term Loan Due 2017 [Member]
Guaranty fees	3,083	$ 0	7,091	$ 0
Second Term Loan Due 2034 [Member]
Interest accrued	74,111		74,111
Principal balance outstanding	1,000,000		1,000,000
Guaranty fees	49,420	0	99,168	0
First Term Loan Due 2034 [Member]
Guaranty fees	$ 121,739	$ 0	$ 0	$ 244,372

10. Accrued Expenses and Othe53

10. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Disclosure Text Block Supplement [Abstract]
Unearned revenue	$ 332,055	$ 781,859
Excise and income taxes payable	273,735	1,290,101
Other payable	152,914	157,714
Transportation and inspection	123,337
Board of director fees payable	101,429	86,429
Property taxes	61,178
Insurance	25,756	103,024
Inspection fees	17,250
Genesis JMA Profit Share payable		388,364
Unrealized hedging loss		183,400
Accrued Expenses and Other Current Liabilities, Net	$ 1,087,654	$ 2,990,891

11. Asset Retirement Obligati54

11. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period			$ 1,985,864	$ 1,866,770	$ 1,866,770
New asset retirement obligations and adjustments					49
Liabilities settled			(59,247)		(92,330)
Accretion expense	$ 28,186	$ 52,720	56,372	$ 105,935	211,375
Asset retirement obligations	1,982,989		1,982,989		1,985,864
Less: asset retirement obligations, current portion	(26,399)		(26,399)		(38,644)
Long-term asset retirement obligations, at the end of the period	$ 1,956,590		$ 1,956,590		$ 1,947,220

11. Asset Retirement Obligati55

11. Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Liabilities settled recognized			$ 59,247		$ 92,330
Abandonment expense	$ 0	$ 0	$ 0	$ 0

12. Treasury Stock (Details Nar

12. Treasury Stock (Details Narrative) - shares	Jun. 30, 2016	Dec. 31, 2015
Equity [Abstract]
Treasury stock	150,000	150,000

13. Concentration of Risk (Deta

13. Concentration of Risk (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Total refined petroleum product sales	$ 41,402,286	$ 58,839,160	$ 72,595,423	$ 119,906,222
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 133,757	$ 234,184	$ 384,304	$ 291,492
Concentration Risk	0.30%	0.40%	0.80%	0.20%
Naphtha
Total refined petroleum product sales	$ 7,287,804	$ 13,413,484	$ 16,313,325	$ 26,829,683
Concentration Risk	17.60%	22.70%	28.90%	22.40%
Jet Fuel
Total refined petroleum product sales	$ 17,539,473	$ 17,411,470	$ 26,045,786	$ 33,930,973
Concentration Risk	42.40%	29.60%	27.30%	28.30%
HOBM
Total refined petroleum product sales	$ 7,889,499	$ 13,622,360	$ 11,052,994	$ 31,031,439
Concentration Risk	19.10%	23.20%	10.10%	25.90%
Reduced crude
Total refined petroleum product sales	$ 546,112		$ 3,791,919
Concentration Risk	1.30%	0.00%	10.40%	0.00%
AGO
Total refined petroleum product sales	$ 8,005,641	$ 14,157,662	$ 15,007,095	$ 27,822,635
Concentration Risk	19.30%	24.10%	22.50%	23.20%

13. Concentration of Risk (De58

13. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Concentration Risk	100.00%	100.00%	100.00%	100.00%
FDIC insurance limit					$ 250,000
Excess of the FDIC insurance limit	$ 13,716,774		$ 13,716,774		$ 19,594,883
Account receivable [Member] | Five customers [Member]
Concentration Risk		82.00%
Concentration risk accounts receivable		$ 5,200,000		$ 5,200,000
Account receivable [Member] | Three customers [Member]
Concentration Risk			58.00%
Sales Revenue [Member] | Five customers [Member]
Concentration Risk			75.40%
Sales Revenue [Member] | Four customers [Member]
Concentration Risk	71.00%		64.00%
Concentration risk accounts receivable	$ 6,200,000		$ 6,200,000
Sales Revenue [Member] | Three customers [Member]
Concentration risk accounts receivable	$ 3,200,000		$ 3,200,000

14. Leases (Details Narrative)

14. Leases (Details Narrative) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Leases, Operating [Abstract]
Rent expense	$ 29,857	$ 57,060	$ 59,715	$ 82,889

15. Income Taxes (Details)

15. Income Taxes (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Current:
Federal		$ 14,038		$ (85,242)
State		(29,701)		(112,554)
Deferred:
Federal	1,534,341	(85,066)	2,653,721	(1,892,551)
Income tax benefit (expense)	$ 1,534,341	$ (100,729)	$ 2,653,721	$ (2,090,347)

15. Income Taxes (Details 2)

15. Income Taxes (Details 2) - USD ($)	3 Months Ended		12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Balance	$ 25,102,740	$ 19,231,390	$ 22,912,701
Net operating loss carryforwards utilized			(3,681,311)
Net operating losses	4,230,763	5,871,350
Balance	29,333,503	25,102,740	19,231,390
Pre-Ownership Change [Member]
Balance	9,614,449	9,614,449	10,766,912
Net operating loss carryforwards utilized			(1,152,463)
Net operating losses
Balance	9,614,449	9,614,449	9,614,449
Post-Ownership Change [Member]
Balance	15,488,291	9,616,941	12,145,789
Net operating loss carryforwards utilized			(2,528,848)
Net operating losses	4,230,763	5,871,350
Balance	$ 19,719,054	$ 15,488,291	$ 9,616,941

15. Income Taxes (Details 3)

15. Income Taxes (Details 3) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 12,243,743	$ 8,815,794
Start-up costs (Nixon Facility)	1,442,032	1,510,699
Asset retirement obligations liability/deferred revenue	709,657	717,723
Unrealized hedges		62,356
AMT credit and other	275,857	302,086
Total deferred tax assets	14,671,289	11,408,658
Deferred tax liabilities:
Fair market value adjustments	(46,116)	(46,116)
Unrealized hedges	(68,663)
Basis differences in property and equipment	(5,978,709)	(5,484,983)
Total deferred tax liabilities	(6,093,488)	(5,531,099)
Deferred tax assets, net	8,577,801	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets, net	$ 6,307,479	$ 3,607,237

15. Income Taxes (Details Narra

15. Income Taxes (Details Narrative) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets	$ 6,300,000		$ 3,600,000
Valuation allowance	$ 2,300,000	$ 2,300,000

16. Earnings per share (Details

16. Earnings per share (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (3,162,736)	$ 137,879	$ (5,311,820)	$ 3,839,243
Basic and diluted income per share	$ (0.30)	$ 0.01	$ (0.51)	$ 0.37
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,459,996	10,450,210	10,458,895	10,444,829

17. Fair Value Measurement (Det

17. Fair Value Measurement (Details) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Financial assets (liabilties):
Commodity contracts	$ 201,950	$ (183,400)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Financial assets (liabilties):
Commodity contracts	201,950	(183,400)
Significant Other Observable Inputs (Level 2) [Member]
Financial assets (liabilties):
Commodity contracts
Significant Unobservable Inputs (Level 3) [Member]
Financial assets (liabilties):
Commodity contracts

17. Fair Value Measurement (D66

17. Fair Value Measurement (Details Narrative) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of long term debt and short-term notes payable	$ 36,227,804	$ 34,781,186

18. Inventory Risk Management67

18. Inventory Risk Management (Details) - Refined products - net short (long) positions	Jun. 30, 2016shares
Volume in Thousands of barrels
Notional Contract Volumes 2016	330,000
Notional Contract Volumes 2017
Notional Contract Volumes 2018

18. Inventory Risk Management68

18. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 201,950		$ 201,950		$ (183,400)
Cost of refined products sold	$ (3,852,100)	$ (1,370,293)	$ (3,359,572)	$ (442,709)

19. Commitments and Contingen69

19. Commitments and Contingencies (Details Narrative) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Credit and cash backed rights of way bonds issued to the BOEM	$ 900,000	$ 900,000