Blue Dolphin Energy (BDCO) 10-Q 16 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 16, 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	Mar. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,458,400
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2,016

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 560,273	$ 1,853,875
Restricted cash	3,013,035	3,175,299
Accounts receivable, net	3,326,561	5,457,245
Prepaid expenses and other current assets	1,357,672	939,690
Deposits	229,933	395,414
Inventory	14,850,967	7,808,318
Deferred tax assets, current portion, net	4,845,465	3,486,746
Total current assets	28,183,906	23,116,587
Total property and equipment, net	53,147,209	48,841,812
Restricted cash, noncurrent	12,551,748	15,616,478
Surety bonds	1,022,000	1,022,000
Trade name	$ 303,346	303,346
Deferred tax assets, net		120,491
Total long-term assets	$ 67,024,303	65,904,127
TOTAL ASSETS	95,208,209	89,020,714
CURRENT LIABILITIES
Accounts payable	24,696,745	14,882,714
Accounts payable, related party	408,556	300,000
Asset retirement obligations, current portion	38,644	38,644
Accrued expenses and other current liabilities	1,719,195	2,990,891
Interest payable, current portion	87,558	81,467
Long-term debt less unamortized debt issue costs, current portion	32,942,090	1,934,932
Total current liabilities	59,892,788	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,939,363	1,947,220
Deferred revenues and expenses	114,661	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,392,787	32,846,254
Long-term interest payable, net of current portion	1,534,661	$ 1,482,801
Deferred tax liabilities, net	72,327
Total long-term liabilities	5,053,799	$ 36,401,360
TOTAL LIABILITIES	$ 64,946,587	$ 56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,608,400 and 10,603,802 shares issued at March 31, 2016 and December 31, 2015, respectively)	$ 106,084	$ 106,038
Additional paid-in capital	36,758,691	36,738,737
Accumulated deficit	(5,803,153)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	30,261,622	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 95,208,209	$ 89,020,714

Consolidated Balance Sheets (U3

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,608,400	10,603,802
Common stock, shares outstanding	10,608,400	10,603,802
Treasury stock, shares	150,000	150,000

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 31,193,137	$ 61,067,062
Tank rental revenue	291,487	286,892
Pipeline operations	27,652	38,395
Total revenue from operations	31,512,276	61,392,349
COST OF OPERATIONS
Cost of refined products sold	30,993,477	49,387,449
Refinery operating expenses	3,437,015	2,880,971
Joint Marketing Agreement profit share	(671,092)	2,438,637
Pipeline operating expenses	79,290	46,596
Lease operating expenses	14,652	7,316
General and administrative expenses	357,004	345,884
Depletion, depreciation and amortization	440,453	$ 399,231
Recovery of bad debt	(139,868)
Accretion expense	28,186	$ 53,215
Total cost of operations	34,539,117	55,559,299
Income (loss) from operations	(3,026,841)	5,833,050
OTHER INCOME (EXPENSE)
Easement, interest and other income	131,763	66,007
Interest and other expense	(419,907)	(208,075)
Total other expense	(288,144)	(142,068)
Income (loss) before income taxes	(3,314,985)	5,690,982
Income tax benefit (expense)	1,165,901	(1,989,618)
Net income (loss)	$ (2,149,084)	$ 3,701,364
Income (loss) per common share:
Basic	$ (0.21)	$ 0.35
Diluted	$ (0.21)	$ 0.35
Weighted average number of common shares outstanding:
Basic	10,457,794	10,449,444
Diluted	10,457,794	10,449,444

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING ACTIVITIES
Net income (loss)	$ (2,149,084)	$ 3,701,364
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	440,453	399,231
Unrealized loss (gain) on derivatives	(1,374,040)	548,190
Deferred tax expense (benefit)	(1,165,901)	1,807,484
Amortization of debt issue costs	32,122	8,450
Accretion expense	28,186	$ 53,215
Common stock issued for services	20,000
Recovery of bad debt	(139,868)
Changes in operating assets and liabilities
Accounts receivable	2,270,552	$ (1,536,092)
Prepaid expenses and other current assets	772,658	650,694
Deposits and other assets	165,481	(80,513)
Inventory	(7,042,649)	129,941
Accounts payable, accrued expenses and other liabilities	7,631,014	(2,046,849)
Accounts payable, related party	108,556	(1,054,523)
Net cash provided by (used in) operating activities	(402,520)	2,580,592
INVESTING ACTIVITIES
Capital expenditures	(3,639,645)	$ (1,291,915)
Change in restricted cash for investing activities	3,064,730
Net cash used in investing activities	(574,915)	$ (1,291,915)
FINANCING ACTIVITIES
Payments on long-term debt	(478,431)	(300,106)
Change in restricted cash for financing activities	162,264	(2,598)
Net cash used in financing activities	(316,167)	(302,704)
Net increase (decrease) in cash and cash equivalents	(1,293,602)	985,973
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	560,273	$ 2,279,206
Non-cash investing and financing activities:
Financing of capital expenditures via capital lease	1,106,205
Interest paid	$ 668,343	$ 165,513
Income taxes paid

1. Organization

1. Organization	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations Structure and Management Our operations are conducted through the following operating subsidiaries: • Lazarus Energy, LLC, a Delaware limited liability company (“LE”); • Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”); • Blue Dolphin Pipe Line Company, a Delaware corporation; • Blue Dolphin Petroleum Company, a Delaware corporation; and • 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 Annual Report 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. Operating Risks As of March 31, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign Bank, a Texas state bank (“Sovereign”). We are currently making our scheduled monthly payments in accordance with the terms and conditions of the loan agreements. See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to Sovereign, 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 Energy, LLC “(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. These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain these relationships or our relationships are not on good terms, it could have a material adverse effect on our operations, liquidity and financial condition. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to Genesis, the Joint Marketing Agreement, and the Crude Supply Agreement. We believe that our cash flows from operations, existing cash and cash equivalents, and proceeds from credit facilities will be sufficient to support our operations and capital expenditures for the next 12 to 18 months. However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and the financial flexibility to attract long-term capital 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 operational strategy will achieve the anticipated outcomes. In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

2. Basis of Presentation

2. Basis of Presentation	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block [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 at 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 months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016, or for any other period.

3. Significant Accounting Polic

3. Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Significant Accounting Policies	The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management who is responsible for its 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 Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis 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” of this Quarterly Report 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 at March 31, 2016 or December 31, 2015. Pipelines and Facilities Oil and Gas Properties Construction in Progress See “Note (7) Property, Plant and Equipment, Net” of this Quarterly Report 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 Customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in 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 some 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” of this Quarterly Report 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” of this Quarterly Report 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 Accounting Pronouncement , Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs New Pronouncements Issued But Not Yet Effective ASU 2016-02, Leases (Topic 842) ASU 2015-17, Income Taxes (Topic 740) 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) ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU 2016-08, evenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), ASU 2014-09 ASU 2015-14 ASU 2016-08 Revenue from Contracts with Customers (Topic 606) Other new pronouncements issued but not effective until after March 31, 2016 are not expected to have a material impact on our financial position, results of operations or liquidity.

4. Business Segment Information

4. Business Segment Information	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2016 and 2015 (and at March 31, 2016 and 2015), was as follows: Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 Segment Segment Refinery Operations Pipeline Transportation Corporate & Other Total Refinery Operations Pipeline Transportation Corporate & Other Total Revenue from operations $ 31,484,624 $ 27,652 $ - $ 31,512,276 $ 61,353,954 $ 38,395 $ - $ 61,392,349 Less: cost of operations(1) (34,422,853 ) (122,128 ) (224,775 ) (34,769,756 ) (52,259,470 ) (53,912 ) (408,048 ) (52,721,430 ) Other non-interest income(2) - 130,665 - 130,665 - 62,500 - 62,500 Adjusted EBITDA (2,938,229 ) 36,189 (224,775 ) (3,126,815 ) 9,094,484 46,983 (408,048 ) 8,733,419 Less: JMA Profit Share(3) 671,092 - - 671,092 (2,438,637 ) - - (2,438,637 ) EBITDA $ (2,267,137 ) $ 36,189 $ (224,775 ) $ 6,655,847 $ 46,983 $ (408,048 ) Depletion, depreciation and amortization (440,453 ) (399,231 ) Interest expense, net (418,809 ) (204,569 ) Income (loss) before income taxes (3,314,985 ) 5,690,982 Income tax benefit (expense) 1,165,901 (1,989,618 ) Net income (loss) $ (2,149,084 ) $ 3,701,364 Capital expenditures $ 3,639,645 $ - $ - $ 3,639,645 $ 1,291,915 $ - $ - $ 1,291,915 Identifiable assets $ 87,970,266 $ 2,026,778 $ 5,211,165 $ 95,208,209 $ 53,361,470 $ 2,923,368 $ 4,355,252 $ 60,640,090 (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” of this Quarterly Report for further discussion related to FLNG. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

5. Prepaid Expenses and Other C

5. Prepaid Expenses and Other Current Assets	3 Months Ended
	Mar. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Unrealized hedging gains $ 1,190,640 $ - Prepaid insurance 155,782 315,120 Prepaid listing fees 11,250 - Prepaid related party operating expenses - 624,570 $ 1,357,672 $ 939,690

6. Inventory

6. Inventory	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory for the periods indicated consisted of the following: March 31, December 31, 2016 2015 HOBM $ 8,327,943 $ 5,007,576 Jet fuel 5,547,597 2,045,784 Naphtha 427,496 309,850 AGO 408,152 278,278 Chemicals 101,063 122,777 Crude oil and condensate 19,041 19,041 Propane 11,212 17,860 LPG mix 8,463 7,152 $ 14,850,967 $ 7,808,318 Product mix and inventory levels may fluctuate from one period to the next to capture market opportunities. At March 31, 2016, our diesel and jet fuel inventory increased intentionally compared to December 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Refinery and facilities $ 43,046,528 $ 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 46,754,903 43,896,303 Less: Accumulated depletion, depreciation, and amortization (6,674,613 ) (6,234,161 ) 40,080,290 37,662,142 Construction in progress 13,066,919 11,179,670 $ 53,147,209 $ 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 amortized over the asset’s useful life. Interest cost capitalized was $954,134 and $556,032 at March 31, 2016 and December 31, 2015, respectively.

8. Accounts Payable, Related Pa

8. Accounts Payable, Related Party	3 Months Ended
	Mar. 31, 2016
Payables and Accruals [Abstract]
Accounts Payable, Related Party	Accounts payable, related party totaled $408,556 and $300,000 at March 31, 2016 and December 31, 2015, respectively. Accounts payable, related party consisted of reimbursements and fees under the Operating Agreement, off-site storage tank leasing expense, and guaranty fee expense related to certain of our long-term debt. Short-Term Tank Lease Agreement At March 31, 2016 and December 31, 2015, accounts payable, related party to Ingleside totaled $172,389 and $300,000, respectively. For the three months ended March 31, 2016 and 2015, fees to Ingleside totaled $275,000 (approximately $0.23 per bbl of throughput) and $0, respectively, and were reflected as refinery operating expenses in our consolidated statements of operations. Operating Agreement For services rendered, LEH receives reimbursements and fees as follows: • Reimbursements At March 31, 2016, accounts payable, related party to LEH totaled $77,836. At December 31, 2015, prepaid related party operating expenses to LEH totaled $624,570. See “Note (5) Prepaid Expenses and Other Current Assets” of this Quarterly Report for additional disclosures with respect to related party expenses. • Fees For the three months ended March 31, 2016 and 2015, fees to LEH totaled $3,162,017 (approximately $2.67 per bbl of throughput) and $2,880,971 (approximately $2.71 per bbl of throughput), respectively, and were reflected as refinery operating expenses in our consolidated statements of income. Guaranty Fees Agreements

9. Long-Term Debt, Net

9. Long-Term Debt, Net	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt, Net	Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, consisted of the following for the periods indicated: March 31, 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 24,464,586 (1,601,787 ) 22,862,799 24,643,081 (1,623,810 ) 23,019,271 Second Term Loan Due 2034 9,926,704 (757,572 ) 9,169,132 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 739,974 - 739,974 924,969 - 924,969 Capital Leases 262,972 - 262,972 304,618 - 304,618 $ 36,694,236 $ (2,359,359 ) $ 34,334,877 $ 37,172,668 $ (2,391,482 ) $ 34,781,186 Less: Long-term debt less unamortized debt issue costs, current portion (32,942,090 ) (1,934,932 ) $ 1,392,787 $ 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) consisted of the following for the periods indicated: March 31, December 31, 2016 2015 Notre Dame Debt 1,534,661 1,482,801 First Term Loan Due 2034 45,894 34,883 Second Term Loan Due 2034 34,630 39,193 Term Loan Due 2017 4,779 4,779 Capital Leases 2,255 2,612 $ 1,622,219 $ 1,564,268 Less: Interest payable, current portion (87,558 ) (81,467 ) $ 1,534,661 $ 1,482,801 First Term Loan Due 2034 pursuant to a term loan in the principal amount of $25.0 million As of March 31, 2016, LE was in violation of the debt service coverage ratio and the current ratio financial covenants under the First Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 has been classified within the current portion of long-term debt, on our consolidated balance sheets. See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the First Term Loan Due 2034. As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee r epayment Proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed to American First National Bank under the Refinery Note. Remaining proceeds are being used primarily to construct new petroleum storage tanks. 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 March 31, 2016, LRM was in violation of the debt service coverage ratio and the current ratio financial covenants under the Second Term Loan Due 2034. Accordingly, the Second Term Loan Due 2034 has been classified within the current portion of long-term debt on our consolidated balance sheets. See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the Second Term Loan Due 2034. 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 P. 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 March 31, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,747 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” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll. Proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan to 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 Tanks 62, 63, and 80, with respect to which Sovereign will have 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. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for additional disclosures related to the Genesis Agreements. Term Loan Due 2017 As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee r epayment The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and certain assets of LEH. See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll. Capital Leases A summary of equipment held under long-term capital leases for the periods indicated follows: March 31, 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	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block Supplement [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Excise and income taxes payable $ 1,080,083 $ 1,290,101 Unearned revenue 315,000 781,859 Other payable 131,115 157,714 Board of director fees payable 98,929 86,429 Insurance 64,390 103,024 Property taxes 29,678 - Genesis JMA Profit Share payable - 388,364 Unrealized hedging loss - 183,400 $ 1,719,195 $ 2,990,891

11. Asset Retirement Obligation

11. Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Refinery and Facilities Pipelines and Facilities and Oil and Gas Properties Changes to our ARO liability for the periods indicated were as follows: March 31, 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 (36,043 ) (92,330 ) Accretion expense 28,186 211,375 1,978,007 1,985,864 Less: asset retirement obligations, current portion (38,644 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 1,939,363 $ 1,947,220 Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability and are reflected in our consolidated balance sheets. At March 31, 2016 and December 31, 2015, we recognized $36,043 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 March 31, 2016 and 2015, we recognized $0 in abandonment expense.

12. Treasury Stock

12. Treasury Stock	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Treasury Stock	At March 31, 2016 and December 31, 2015, we had 150,000 shares of treasury stock.

13. Concentration of Risk

13. Concentration of Risk	3 Months Ended
	Mar. 31, 2016
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier Significant Customers Refined Petroleum Product Sales Three Months Ended March 31, 2016 2015 LPG mix $ 250,547 0.8 % $ 57,308 0.0 % Naphtha 9,025,521 28.9 % 13,416,199 22.0 % Jet fuel 8,506,313 27.3 % 16,519,503 27.1 % HOBM 3,163,495 10.1 % 17,409,079 28.5 % Reduced Crude 3,245,807 10.4 % - 0.0 % AGO 7,001,454 22.5 % 13,664,973 22.4 % $ 31,193,137 100.0 % $ 61,067,062 100.0 % For the three months ended March 31, 2016 we sold less bbls of diesel and jet fuel as a result of intentionally increasing inventory compared to the three months ended March 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

14. Leases

14. Leases	3 Months Ended
	Mar. 31, 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 expiring in 2017, includes free rent periods and escalating rent payment provisions, and requires payment of a portion of related actual operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended March 31, 2016 and 2015, rent expense totaled $29,857 and $25,829, respectively.

15. Income Taxes

15. Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Benefit (Expense) Three Months Ended March 31, 2016 2015 Current: Federal $ - $ (99,281 ) State - (82,853 ) Deferred: Federal 1,165,901 (1,807,484 ) $ 1,165,901 $ (1,989,618 ) 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 Post-Ownership 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 Deferred Tax Assets and Liabilities March 31, December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,805,253 $ 8,815,794 Start-up costs (Nixon Facility) 1,476,365 1,510,699 Asset retirement obligations liability/deferred revenue 711,507 717,723 Unrealized hedges - 62,356 AMT credit and other 219,814 302,086 Total deferred tax assets 13,212,939 11,408,658 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (404,818 ) - Basis differences in property and equipment (5,718,545 ) (5,484,983 ) Total deferred tax liabilities (6,169,479 ) (5,531,099 ) Deferred tax assets, net 7,043,460 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) $ 4,773,138 $ 3,607,237 Deferred tax assets (liabilities) on a current and noncurrent basis for the periods indicated were as follow: March 31, December 31, 2016 2015 Current deferred tax assets $ 4,845,465 $ 3,486,746 Noncurrent deferred tax assets, net 2,197,995 2,390,813 Deferred tax assets, net 7,043,460 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) $ 4,773,138 $ 3,607,237 Valuation Allowance 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 months ended March 31, 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	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended March 31, 2016 2015 Net income (loss) $ (2,149,084 ) $ 3,701,364 Basic and diluted income per share $ (0.21 ) $ 0.35 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,457,794 10,449,444 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three months ended March 31, 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	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	We have determined the fair value of certain assets and liabilities through the application of fair value measurements and disclosures, which establish a framework for measuring fair value. We are subject to gains or losses on certain financial assets based on our various agreements and understandings with Genesis. Pursuant to these agreements and understandings, Genesis may execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity price risks associated with our refined petroleum products and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil and condensate. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreement with Genesis, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments by Genesis. 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 the fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The fair value hierarchy consists of the following three levels: Level 1 Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data. Level 3 Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs. The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2015 and 2014 due to their short-term maturities. The fair value of our long-term debt, net including the current portion at March 31, 2016 and December 31, 2015 was $34,334,877 and $34,781,186, 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 March 31, 2016 and December 31, 2015 and the basis for the measurement: Fair Value Measurement at March 31, 2016 Using Financial assets (liabilities): Carrying Value at March 31, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Significant Commodity contracts $ 1,190,640 $ 1,190,640 $ - $ - Fair Value Measurement at March 31, 2016 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 executed by Genesis are reflected as other current assets or other current liabilities in our consolidated balance sheets.

18. Inventory Risk Management

18. Inventory Risk Management	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Inventory Risk Management	Management periodically determines whether to maintain, increase, or decrease inventory levels based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows. Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts 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 by Genesis 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 by Genesis to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a commodity futures contract is made solely by Genesis, Genesis typically confers with management as part of Genesis’ decision making process. 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. Additionally, Genesis may be required to collateralize any mark-to-market losses on outstanding commodity futures contracts. As of March 31, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. 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 460,000 - - The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2016 and December 31, 2015: Fair Value March 31, December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ 1,190,640 $ (183,400 ) The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2016 and 2015: Gain (Loss) Recognized Three Months Ended March 31, Derivatives Statements of Operations Location 2016 2015 Commodity contracts Cost of refined products sold $ (492,528 ) $ 927,584

19. Commitments and Contingenci

19. Commitments and Contingencies	3 Months Ended
	Mar. 31, 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 plus the amount of any accounting fees, if incurred, not to exceed $50,000 per month. We assigned our rights to weekly 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 shall be paid 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share and we shall be paid 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and us in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the our Profit Share. The GEL Profit Share plus the Performance Fee are collectively referred to in this Quarterly Report as the Joint Marketing Agreement Profit Share (the “JMA Profit Share”). The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. For example, we are prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. 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, a Texas state bank (“Sovereign”), as lender and lienholder pursuant to that certain Loan and Security Agreement LE has a dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement. On May 2, 2016, GEL filed a lawsuit in Texas state court in Harris County. On May 13, 2016, LE filed a Demand for Arbitration with the American Arbitration Association to bring the dispute to resolution. We are not presently able to reasonably estimate the outcome related to the lawsuit and as such, have not recorded a liability in the consolidated balance sheets. FLNG Master Easement Agreement Supplemental Pipeline Bonds In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking outlining proposed changes to financial assurance requirements in order to modernize financial assurance and risk management and better address potential costs and liabilities of offshore energy development. Part of the Advanced Notice of Proposed Rulemaking includes the BOEM revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit based model. Following a public comment period, the BOEM plans to publish a revised notice to lessees in 2016 that will outline new financial assurance requirements. 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. We are currently working with the BOEM to develop a tailored plan to address the financial assurance requirements. 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. At March 31, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. Financing Agreements Nixon Facility Expansion e Legal Matters Health, Safety and Environmental Matters

3. Significant Accounting Pol25

3. Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable 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 Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis 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” of this Quarterly Report 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 at March 31, 2016 or December 31, 2015. Pipelines and Facilities Oil and Gas Properties Construction in Progress See “Note (7) Property, Plant and Equipment, Net” of this Quarterly Report 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 Customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in 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 some 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” of this Quarterly Report 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” of this Quarterly Report 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 Accounting Pronouncement	New Accounting Pronouncement , 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 2016-02, Leases (Topic 842) ASU 2015-17, Income Taxes (Topic 740) 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) ASU 2015-14, evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU 2016-08, evenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), ASU 2014-09 ASU 2015-14 ASU 2016-08 Revenue from Contracts with Customers (Topic 606) Other new pronouncements issued but not effective until after March 31, 2016 are not expected to have a material impact on our financial position, results of operations or liquidity.

4. Business Segment Informati26

4. Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Business segment reporting	Business segment information for the three months ended March 31, 2016 and 2015 (and at March 31, 2016 and 2015), was as follows: Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 Segment Segment Refinery Operations Pipeline Transportation Corporate & Other Total Refinery Operations Pipeline Transportation Corporate & Other Total Revenue from operations $ 31,484,624 $ 27,652 $ - $ 31,512,276 $ 61,353,954 $ 38,395 $ - $ 61,392,349 Less: cost of operations(1) (34,422,853 ) (122,128 ) (224,775 ) (34,769,756 ) (52,259,470 ) (53,912 ) (408,048 ) (52,721,430 ) Other non-interest income(2) - 130,665 - 130,665 - 62,500 - 62,500 Adjusted EBITDA (2,938,229 ) 36,189 (224,775 ) (3,126,815 ) 9,094,484 46,983 (408,048 ) 8,733,419 Less: JMA Profit Share(3) 671,092 - - 671,092 (2,438,637 ) - - (2,438,637 ) EBITDA $ (2,267,137 ) $ 36,189 $ (224,775 ) $ 6,655,847 $ 46,983 $ (408,048 ) Depletion, depreciation and amortization (440,453 ) (399,231 ) Interest expense, net (418,809 ) (204,569 ) Income (loss) before income taxes (3,314,985 ) 5,690,982 Income tax benefit (expense) 1,165,901 (1,989,618 ) Net income (loss) $ (2,149,084 ) $ 3,701,364 Capital expenditures $ 3,639,645 $ - $ - $ 3,639,645 $ 1,291,915 $ - $ - $ 1,291,915 Identifiable assets $ 87,970,266 $ 2,026,778 $ 5,211,165 $ 95,208,209 $ 53,361,470 $ 2,923,368 $ 4,355,252 $ 60,640,090 (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” of this Quarterly Report for further discussion related to FLNG. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

5. Prepaid Expenses and Other27

5. Prepaid Expenses and Other Current Assets (Tables)	3 Months Ended
	Mar. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid balances	Prepaid expenses and other current assets for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Unrealized hedging gains $ 1,190,640 $ - Prepaid insurance 155,782 315,120 Prepaid listing fees 11,250 - Prepaid related party operating expenses - 624,570 $ 1,357,672 $ 939,690

6. Inventory (Tables)

6. Inventory (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory for the periods indicated consisted of the following: March 31, December 31, 2016 2015 HOBM $ 8,327,943 $ 5,007,576 Jet fuel 5,547,597 2,045,784 Naphtha 427,496 309,850 AGO 408,152 278,278 Chemicals 101,063 122,777 Crude oil and condensate 19,041 19,041 Propane 11,212 17,860 LPG mix 8,463 7,152 $ 14,850,967 $ 7,808,318

7. Property, Plant and Equipm29

7. Property, Plant and Equipment, Net (Tables)	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Property and equipment	Property, plant and equipment, net, for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Refinery and facilities $ 43,046,528 $ 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 46,754,903 43,896,303 Less: Accumulated depletion, depreciation, and amortization (6,674,613 ) (6,234,161 ) 40,080,290 37,662,142 Construction in progress 13,066,919 11,179,670 $ 53,147,209 $ 48,841,812

9. Long-Term Debt, Net (Tables)

9. Long-Term Debt, Net (Tables)	3 Months Ended
	Mar. 31, 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, consisted of the following for the periods indicated: March 31, 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 24,464,586 (1,601,787 ) 22,862,799 24,643,081 (1,623,810 ) 23,019,271 Second Term Loan Due 2034 9,926,704 (757,572 ) 9,169,132 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 739,974 - 739,974 924,969 - 924,969 Capital Leases 262,972 - 262,972 304,618 - 304,618 $ 36,694,236 $ (2,359,359 ) $ 34,334,877 $ 37,172,668 $ (2,391,482 ) $ 34,781,186 Less: Long-term debt less unamortized debt issue costs, current portion (32,942,090 ) (1,934,932 ) $ 1,392,787 $ 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) consisted of the following for the periods indicated: March 31, December 31, 2016 2015 Notre Dame Debt 1,534,661 1,482,801 First Term Loan Due 2034 45,894 34,883 Second Term Loan Due 2034 34,630 39,193 Term Loan Due 2017 4,779 4,779 Capital Leases 2,255 2,612 $ 1,622,219 $ 1,564,268 Less: Interest payable, current portion (87,558 ) (81,467 ) $ 1,534,661 $ 1,482,801
Schedule of summary of equipment held under long-term capital leases	A summary of equipment held under long-term capital leases for the periods indicated follows: March 31, December 31, 2016 2015 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598

10. Accrued Expenses and Othe31

10. Accrued Expenses and Other Current Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block Supplement [Abstract]
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities for the periods indicated consisted of the following: March 31, December 31, 2016 2015 Excise and income taxes payable $ 1,080,083 $ 1,290,101 Unearned revenue 315,000 781,859 Other payable 131,115 157,714 Board of director fees payable 98,929 86,429 Insurance 64,390 103,024 Property taxes 29,678 - Genesis JMA Profit Share payable - 388,364 Unrealized hedging loss - 183,400 $ 1,719,195 $ 2,990,891

11. Asset Retirement Obligati32

11. Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Changes to our ARO liability for the periods indicated were as follows: March 31, 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 (36,043 ) (92,330 ) Accretion expense 28,186 211,375 1,978,007 1,985,864 Less: asset retirement obligations, current portion (38,644 ) (38,644 ) Long-term asset retirement obligations, at the end of the period $ 1,939,363 $ 1,947,220

13. Concentration of Risk (Tabl

13. Concentration of Risk (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016 2015 LPG mix $ 250,547 0.8 % $ 57,308 0.0 % Naphtha 9,025,521 28.9 % 13,416,199 22.0 % Jet fuel 8,506,313 27.3 % 16,519,503 27.1 % HOBM 3,163,495 10.1 % 17,409,079 28.5 % Reduced Crude 3,245,807 10.4 % - 0.0 % AGO 7,001,454 22.5 % 13,664,973 22.4 % $ 31,193,137 100.0 % $ 61,067,062 100.0 %

15. Income Taxes (Tables)

15. Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Income tax benefit (expense) for the periods indicated consisted of the following: Three Months Ended March 31, 2016 2015 Current: Federal $ - $ (99,281 ) State - (82,853 ) Deferred: Federal 1,165,901 (1,807,484 ) $ 1,165,901 $ (1,989,618 )
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 Post-Ownership 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
Deferred tax assets and deferred tax liabilities	Significant components of deferred tax assets and liabilities for the periods indicated were as follow: March 31, December 31, 2016 2015 Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,805,253 $ 8,815,794 Start-up costs (Nixon Facility) 1,476,365 1,510,699 Asset retirement obligations liability/deferred revenue 711,507 717,723 Unrealized hedges - 62,356 AMT credit and other 219,814 302,086 Total deferred tax assets 13,212,939 11,408,658 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (404,818 ) - Basis differences in property and equipment (5,718,545 ) (5,484,983 ) Total deferred tax liabilities (6,169,479 ) (5,531,099 ) Deferred tax assets, net 7,043,460 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) $ 4,773,138 $ 3,607,237
Current and noncurrent deferred tax assets (liabilities)	Deferred tax assets (liabilities) on a current and noncurrent basis for the periods indicated were as follow: March 31, December 31, 2016 2015 Current deferred tax assets $ 4,845,465 $ 3,486,746 Noncurrent deferred tax assets, net 2,197,995 2,390,813 Deferred tax assets, net 7,043,460 5,877,559 Valuation allowance (2,270,322 ) (2,270,322 ) $ 4,773,138 $ 3,607,237

16. Earnings Per Share (Tables)

16. Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings per share	A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended March 31, 2016 2015 Net income (loss) $ (2,149,084 ) $ 3,701,364 Basic and diluted income per share $ (0.21 ) $ 0.35 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,457,794 10,449,444

17. Fair Value Measurement (Tab

17. Fair Value Measurement (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016 and December 31, 2015 and the basis for the measurement: Fair Value Measurement at March 31, 2016 Using Financial assets (liabilities): Carrying Value at March 31, 2016 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Significant Commodity contracts $ 1,190,640 $ 1,190,640 $ - $ - Fair Value Measurement at March 31, 2016 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)	3 Months Ended
	Mar. 31, 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 460,000 - -
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 at March 31, 2016 and December 31, 2015: Fair Value March 31, December 31, Asset Derivatives Balance Sheets Location 2016 2015 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ 1,190,640 $ (183,400 )
Effect of derivative instruments	The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2016 and 2015: Gain (Loss) Recognized Three Months Ended March 31, Derivatives Statements of Operations Location 2016 2015 Commodity contracts Cost of refined products sold $ (492,528 ) $ 927,584

1. Organization (Details Narrat

1. Organization (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and cash equivalents	$ 560,273	$ 1,853,875	$ 2,279,206	$ 1,293,233

3. Significant Accounting Pol39

3. Significant Accounting Policies (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 560,273	$ 1,853,875	$ 2,279,206	$ 1,293,233
Restricted cash	3,013,035	3,175,299
Restricted cash, noncurrent	12,551,748	15,616,478
Allowance for doubtful accounts	0	139,868
Trade name	303,346	303,346
Debt issue costs	$ 2,400,000	$ 2,400,000

4. Business Segment Informati40

4. Business Segment Information (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Revenue from operations		$ 31,512,276	$ 61,392,349
Income tax benefit (expense)		(1,165,901)	1,989,618
Net income (loss)		(2,149,084)	3,701,364
Refinery Operations [Member]
Revenue from operations		31,484,624	61,353,954
Less: cost of operations	[1]	$ (34,422,853)	$ (52,259,470)
Other non-interest income	[2]
Adjusted EBITDA		$ (2,938,229)	$ 9,094,484
Less: JMA Profit Share	[3]	671,092	(2,438,637)
EBITDA		(2,267,137)	6,655,847
Capital expenditures		3,639,645	1,291,915
Identifiable assets		87,970,266	53,361,470
Pipeline Transportation [Member]
Revenue from operations		27,652	38,395
Less: cost of operations	[1]	(122,128)	(53,912)
Other non-interest income	[2]	130,665	62,500
Adjusted EBITDA		$ 36,189	$ 46,983
Less: JMA Profit Share	[3]
EBITDA		$ 36,189	$ 46,983
Capital expenditures
Identifiable assets		$ 2,026,778	$ 2,923,368
Corporate and Other [Member]
Revenue from operations
Less: cost of operations	[1]	$ (224,775)	$ (408,048)
Other non-interest income	[2]
Adjusted EBITDA		$ (224,775)	$ (408,048)
Less: JMA Profit Share	[3]
EBITDA		$ (224,775)	$ (408,048)
Capital expenditures
Identifiable assets		$ 5,211,165	$ 4,355,252
Total
Revenue from operations		31,512,276	61,392,349
Less: cost of operations	[1]	(34,769,756)	(52,721,430)
Other non-interest income	[2]	130,665	62,500
Adjusted EBITDA		(3,126,815)	8,733,419
Less: JMA Profit Share	[3]	671,092	(2,438,637)
Depletion, depreciation and amortization		(440,453)	(399,231)
Interest expense, net		(418,809)	(204,569)
Income (loss) before income taxes		(3,314,985)	5,690,982
Income tax benefit (expense)		1,165,901	(1,989,618)
Net income (loss)		(2,149,084)	3,701,364
Capital expenditures		3,639,645	1,291,915
Identifiable assets		$ 95,208,209	$ 60,640,090
[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 Contingenciesb - FLNG Master Easement Agreement" of this Quarterly Report for further discussion related to FLNG.
[3]	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See "Note (19) Commitments and Contingencies - Genesis Agreements" of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

5. Prepaid Expenses and Other41

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Unrealized hedging gains	$ 1,190,640
Prepaid insurance	155,782	$ 315,120
Prepaid listing fees	$ 11,250
Prepaid related party operating expenses		$ 624,570
Prepaid Expenses, Net	$ 1,357,672	$ 939,690

6. Inventory (Details)

6. Inventory (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
HOBM	$ 8,327,943	$ 5,007,576
Jet fuel	5,547,597	2,045,784
Naphtha	427,496	309,850
AGO	408,152	278,278
Chemicals	101,063	122,777
Crude oil and condensate	19,041	19,041
Propane	11,212	17,860
LPG mix	8,463	7,152
Inventories, Net	$ 14,850,967	$ 7,808,318

7. Property, Plant and Equipm43

7. Property, Plant and Equipment, Net (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 43,046,528	$ 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	46,754,903	43,896,303
Less: Accumulated depletion, depreciation and amortization	(6,674,613)	(6,234,161)
Property, Plant and Equipment less depreciation	40,080,290	37,662,142
Construction in progress	13,066,919	11,179,670
Property, Plant and Equipment, Net	$ 53,147,209	$ 48,841,812

8. Property, Plant and Equipmen

8. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 954,134	$ 556,032

8. Accounts Payable, Related 45

8. Accounts Payable, Related Party (Details Narrative) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Accounts payable, related party	$ 408,556		$ 300,000
Expense for service	$ 275,000	$ 0
Prepaid related party operating expenses			624,570
Ingleside [Member]
Accounts payable, related party	$ 172,389		300,000
LEH [Member]
Accounts payable, related party	77,836
Expense for service	3,162,017		2,880,971
Prepaid related party operating expenses	624,570
Jonathan Carroll [Member]
Accounts payable, related party	$ 158,331		$ 0

9. Long-Term Debt, Net (Details

9. Long-Term Debt, Net (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Principal balance outstanding	$ 36,694,236	$ 37,172,668
Debt Issue Costs	(2,359,359)	(2,391,482)
Long-Term Debt, Net	34,334,877	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion	(32,942,090)	32,846,254
Long term debt	1,392,787	1,482,801
First Term Loan Due 2034 [Member]
Principal balance outstanding	24,464,586	24,643,081
Debt Issue Costs	(1,601,787)	(1,623,810)
Long-Term Debt, Net	22,862,799	23,019,271
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,926,704	10,000,000
Debt Issue Costs	(757,572)	(767,672)
Long-Term Debt, Net	9,169,132	9,232,328
Long term debt	10,000,000
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
Long term debt	8,000,000
Term Loan Due 2017 [Member]
Principal balance outstanding	$ 739,974	$ 924,969
Debt Issue Costs
Long-Term Debt, Net	$ 739,974	$ 924,969
Long term debt	2,000,000
Capital Leases [Member]
Principal balance outstanding	$ 262,972	$ 304,618
Debt Issue Costs
Long-Term Debt, Net	$ 262,972	$ 304,618

9. Long-Term Debt, Net (Detai47

9. Long-Term Debt, Net (Details 1) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notre Dame Debt	$ 1,534,661	$ 1,482,801
First Term Loan Due 2034	45,894	34,883
Second Term Loan Due 2034	34,630	39,193
Term Loan Due 2017	4,779	4,779
Capital leases	2,255	2,612
Total	1,622,219	1,564,268
Less: Interest payable, current portion	(87,558)	(81,467)
Long term debt	$ 1,534,661	$ 1,482,801

9. Long-Term Debt, Net (Detai48

9. Long-Term Debt, Net (Details 2) - USD ($)	Mar. 31, 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 (Detai49

9. Long-Term Debt, Net (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Principal balance outstanding	$ 1,392,787	$ 1,482,801
Term Loan Due 2017 [Member]
Principal balance outstanding	2,000,000
Guaranty fees	4,008	0
Notre Dame Debt [Member]
Principal balance outstanding	8,000,000
Second Term Loan Due 2034 [Member]
Interest accrued	74,111
Principal balance outstanding	10,000,000
Guaranty fees	49,747	0
First Term Loan Due 2034 [Member]
Guaranty fees	$ 122,633
First Term Loan Due 2034 [Member]
Guaranty fees		$ 0

10. Accrued Expenses and Othe50

10. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Disclosure Text Block Supplement [Abstract]
Excise and income taxes payable	$ 1,080,083	$ 1,290,101
Unearned revenue	315,000	781,859
Other payable	131,115	157,714
Board of director fees payable	98,929	86,429
Insurance	64,390	$ 103,024
Property taxes	$ 29,678
Genesis JMA Profit Share payable		$ 388,364
Unrealized hedging loss		183,400
Accrued Expenses and Other Current Liabilities, Net	$ 1,719,195	$ 2,990,891

11. Asset Retirement Obligati51

11. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 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	$ (36,043)		(92,330)
Accretion expense	28,186	$ 53,215	211,375
Asset retirement obligations	1,978,007		1,985,864
Less: asset retirement obligations, current portion	(38,644)		(38,644)
Long-term asset retirement obligations, at the end of the period	$ 1,939,363		$ 1,947,220

11. Asset Retirement Obligati52

11. Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Liabilities settled recognized	$ 36,043		$ 92,330
Abandonment expense	$ 0	$ 0

12. Treasury Stock (Details Nar

12. Treasury Stock (Details Narrative) - shares	Mar. 31, 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
	Mar. 31, 2016	Mar. 31, 2015
Total refined petroleum product sales	$ 31,193,137	$ 61,067,062
Concentration Risk	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 250,547	$ 57,308
Concentration Risk	0.80%	0.00%
Naphtha
Total refined petroleum product sales	$ 9,025,521	$ 13,416,199
Concentration Risk	28.90%	22.00%
Jet Fuel
Total refined petroleum product sales	$ 8,506,313	$ 16,519,503
Concentration Risk	27.30%	27.10%
HOBM
Total refined petroleum product sales	$ 3,163,495	$ 17,409,079
Concentration Risk	10.10%	28.50%
Reduced crude
Total refined petroleum product sales	$ 3,245,807
Concentration Risk	10.40%	0.00%
AGO
Total refined petroleum product sales	$ 7,001,454	$ 13,664,973
Concentration Risk	22.50%	22.40%

13. Concentration of Risk (De55

13. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250,000		$ 250,000
Excess of the FDIC insurance limit	$ 15,507,858		$ 19,594,883
Sales Revenue [Member] | Five customers [Member]
Concentration Risk	75.40%
Sales Revenue [Member] | Three customers [Member]
Concentration Risk		67.00%
Account receivable [Member] | Five customers [Member]
Concentration risk accounts receivable	$ 2,300,000	$ 4,100,000

14. Leases (Details Narrative)

14. Leases (Details Narrative) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Leases, Operating [Abstract]
Rent expense	$ 29,857	$ 25,829

15. Income Taxes (Details)

15. Income Taxes (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Current:
Federal		$ (99,281)
State		(82,853)
Deferred:
Federal	$ 1,165,901	(1,807,484)
Income tax benefit (expense)	$ 1,165,901	$ (1,989,618)

15. Income Taxes (Details 2)

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

15. Income Taxes (Details 3)

15. Income Taxes (Details 3) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 10,805,253	$ 8,815,794
Start-up costs (Nixon Facility)	1,476,365	1,510,699
Asset retirement obligations liability/deferred revenue	$ 711,507	717,723
Unrealized hedges		62,356
AMT credit and other	$ 219,814	302,086
Total deferred tax assets	13,212,939	11,408,658
Deferred tax liabilities:
Fair market value adjustments	(46,116)	$ (46,116)
Unrealized hedges	(404,818)
Basis differences in property and equipment	(5,718,545)	$ (5,484,983)
Total deferred tax liabilities	(6,169,479)	(5,531,099)
Deferred tax assets, net	7,043,460	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 4,773,138	$ 3,607,237

15. Income Taxes (Details 4)

15. Income Taxes (Details 4) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current deferred tax assets	$ 4,845,465	$ 3,486,746
Noncurrent deferred tax assets, net	2,197,995	2,390,813
Deferred tax assets, net	7,043,460	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 4,773,138	$ 3,607,237

15. Income Taxes (Details Narra

15. Income Taxes (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets	$ 4,800,000	$ 3,600,000

16. Earnings per share (Details

16. Earnings per share (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (2,149,084)	$ 3,701,364
Basic and diluted income per share	$ (0.21)	$ 0.35
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,457,794	10,449,444

17. Fair Value Measurement (Det

17. Fair Value Measurement (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Financial assets (liabilties):
Commodity contracts	$ 1,190,640	$ (183,400)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Financial assets (liabilties):
Commodity contracts	$ 1,190,640	$ (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 (D64

17. Fair Value Measurement (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of long term debt and short-term notes payable	$ 34,334,877	$ 34,781,186

18. Inventory Risk Management65

18. Inventory Risk Management (Details) - Refined products - net short (long) positions	Mar. 31, 2016shares
Volume in Thousands of barrels
Notional Contract Volumes 2016	460,000
Notional Contract Volumes 2017
Notional Contract Volumes 2018

18. Inventory Risk Management66

18. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 1,190,640		$ (183,400)
Cost of refined products sold	$ (492,528)	$ 927,584

19. Commitments and Contingen67

19. Commitments and Contingencies (Details Narrative) - USD ($)	Mar. 31, 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