Blue Dolphin Energy (BDCO) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 30, 2016
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-K
Document Period End Date	Dec. 31, 2015
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		10,453,802
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015
Entity Public Float	$ 10,000,310

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 1,853,875	$ 1,293,233
Restricted cash	3,175,299	1,008,514
Accounts receivable, net	5,457,245	8,340,303
Prepaid expenses and other current assets	939,690	771,458
Deposits	395,414	68,498
Inventory	7,808,318	$ 3,200,651
Deferred tax assets, current portion, net	3,486,746
Total current assets	23,116,587	$ 14,682,657
Total property and equipment, net	48,841,812	37,371,075
Restricted cash, noncurrent	15,616,478	0
Surety bonds	1,022,000	1,642,000
Debt issue costs, net	2,391,482	479,737
Trade name	303,346	303,346
Deferred tax assets, net	120,491	5,928,342
Total long-term assets	68,295,609	45,724,500
TOTAL ASSETS	91,412,196	60,407,157
CURRENT LIABILITIES
Accounts payable	14,882,714	12,370,179
Accounts payable, related party	300,000	1,174,168
Asset retirement obligations, current portion	38,644	85,846
Accrued expenses and other current liabilities	2,990,891	2,783,704
Interest payable, current portion	81,467	56,039
Long-term debt, current portion	$ 1,934,932	1,245,476
Deferred tax liabilities, net		168,236
Total current liabilities	$ 20,228,648	17,883,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,947,220	1,780,924
Deferred revenues and expenses	125,085	691,525
Long-term debt, net of current portion	35,237,736	10,808,803
Long-term interest payable, net of current portion	1,482,801	1,274,789
Total long-term liabilities	38,792,842	14,556,041
TOTAL LIABILITIES	$ 59,021,490	$ 32,439,689
Commitments and contingencies (Note 20)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,603,802 and 10,599,444 shares issued at December 31, 2015 and December 31, 2014, respectively)	$ 106,038	$ 105,995
Additional paid-in capital	36,738,737	36,718,781
Accumulated deficit	(3,654,069)	(8,057,308)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	32,390,706	27,967,468
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 91,412,196	$ 60,407,157

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,603,802	10,599,444
Common stock, shares outstanding	10,603,802	10,599,444
Treasury stock, shares	150,000	150,000

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 220,438,588	$ 387,304,774
Tank rental revenue	1,147,568	1,130,149
Pipeline operations	146,464	220,200
Total revenue from operations	221,732,620	388,655,123
COST OF OPERATIONS
Cost of refined products sold	193,216,959	360,159,711
Refinery operating expenses	11,683,658	10,698,023
Joint Marketing Agreement profit share	5,820,329	3,602,581
Pipeline operating expenses	(142,250)	208,037
Lease operating expenses	30,023	26,428
General and administrative expenses	1,525,577	1,427,707
Depletion, depreciation and amortization	1,647,586	$ 1,570,962
Bad debt expense	139,874
Accretion expense	211,375	$ 211,995
Total cost of operations	214,133,131	377,905,444
Income from operations	7,599,489	10,749,679
OTHER INCOME (EXPENSE)
Easement, interest and other income	980,266	318,271
Interest and other expense	$ (1,742,214)	(892,372)
Loss on disposal of property and equipment		(4,400)
Total other expense	$ (761,948)	(578,501)
Income before income taxes	6,837,541	10,171,178
Income tax benefit (expense)	(2,434,302)	5,587,578
Net income	$ 4,403,239	$ 15,758,756
Income per common share
Basic	$ 0.42	$ 1.51
Diluted	$ 0.42	$ 1.51
Weighted average number of common shares outstanding:
Basic	10,451,832	10,441,464
Diluted	10,451,832	10,441,464

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Treasury Stock	Total
Beginning Balance, shares at Dec. 31, 2013	10,580,973			(150,000)
Beginning Balance, amount at Dec. 31, 2013	$ 105,810	$ 36,623,965	$ (23,816,064)	$ (800,000)	$ 12,113,711
Common stock issued for services, shares	18,471
Common stock issued for services, amount	$ 185	$ 94,816			95,001
Net Income			$ 15,758,756		15,758,756
Ending Balance, shares at Dec. 31, 2014	10,599,444			(150,000)
Ending Balance, amount at Dec. 31, 2014	$ 105,995	$ 36,718,781	$ (8,057,308)	$ (800,000)	27,967,468
Common stock issued for services, shares	4,358
Common stock issued for services, amount	$ 43	$ 19,956			19,999
Net Income			$ 4,403,239		4,403,239
Ending Balance, shares at Dec. 31, 2015	10,603,802			(150,000)
Ending Balance, amount at Dec. 31, 2015	$ 106,038	$ 36,738,737	$ (3,654,069)	$ (800,000)	$ 32,390,706

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
OPERATING ACTIVITIES
Net income	$ 4,403,239	$ 15,758,756
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,647,586	1,570,962
Unrealized loss (gain) on derivatives	679,300	(488,950)
Deferred taxes	2,152,869	(5,760,106)
Amortization of debt issue costs	544,607	33,799
Accretion expense	211,375	211,995
Common stock issued for services	19,999	$ 95,001
Bad debt expense	$ 139,874
Loss on disposal of assets		$ 4,400
Changes in operating assets and liabilities
Accounts receivable	$ 2,883,058	5,146,803
Prepaid expenses and other current assets	(168,232)	(437,775)
Deposits and other assets	293,084	(505,838)
Inventory	(4,607,667)	1,485,748
Accounts payable, accrued expenses and other liabilities	601,603	(6,770,318)
Accounts payable, related party	(874,168)	(2,485,172)
Net cash provided by operating activities	7,926,527	7,859,305
INVESTING ACTIVITIES
Capital expenditures	(12,244,658)	$ (1,720,156)
Change in restricted cash for investing activities	(17,360,475)
Net cash used in investing activities	(29,605,133)	$ (1,720,156)
FINANCING ACTIVITIES
Proceeds from issuance of debt	35,000,000
Payments on long-term debt	(9,881,612)	$ (6,226,521)
Proceeds from notes payable	3,000,000	2,000,000
Payments on notes payable	(3,000,000)	$ (372,986)
Change in debt issue costs, net	(2,456,352)
Change in restricted cash for financing activities	(422,788)	$ (681,126)
Net cash provided by (used in) financing activities	22,239,248	(5,280,633)
Net increase in cash and cash equivalents	560,642	858,516
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,293,233	434,717
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 1,853,875	1,293,233
Non-cash operating activities
Surety bond funded by seller of pipeline interest		850,000
Non-cash investing and financing activities:
New asset retirement obligations		300,980
Financing of capital expenditures via capital lease		$ 536,635
Financing of capital expenditures via accounts payable	$ 873,665
Interest paid	1,608,808	$ 1,369,197
Income taxes paid	$ 139,500	$ 231,552

1. Organization

1. Organization	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	We have prepared our audited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation.

2. Basis of Presentation

2. Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	We have prepared our audited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation.

3. Significant Accounting Polic

3. Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 FASB 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 income. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of income using mark-to-market accounting. See “Note (18) Fair Value Measurement” and “Note (19) Inventory Risk Management” of this Annual Report for additional disclosures related to derivatives. Property and Equipment Refinery and Facilities . Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances. 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 income. 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 the years ended December 31, 2015 and 2014. Pipelines and Facilities . We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. Oil and Gas Properties . We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the years ended December 31, 2015 and 2014. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired at December 31, 2012. Construction in Progress . Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service. See “Note (7) Property, Plant and Equipment, Net” of this Annual 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 Debt Issue Costs Revenue Recognition Refined Petroleum Products Revenue . We sell jet fuel in nearby markets, and our intermediate products, including liquefied petroleum gas, naphtha, HOBM, and atmospheric gas oil (“AGO”), to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. 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 . Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. Easement Revenue . Land easement revenue is recognized monthly as earned and is included in other income. Pipeline Transportation Revenue . Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline. Deferred Revenue . In February 2014, we entered into an Asset Sale Agreement (the “Purchase Agreement”) with WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), whereby we reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline, and the Omega Pipeline (the “Pipeline Assets”) effective in October 2013. Prior to the Purchase Agreement, we owned approximately 83% of the Pipeline Assets. Pursuant to the Purchase Agreement, WBI paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for our benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure. In December 2014, we completed work to abandon-in-place the pipeline associated with Right-of-Way Number OCS-G 08606. In November 2015, the Bureau of Environmental Management released $645,000 in cash collateral backing this supplemental pipeline bond. The remaining $422,373 of deferred revenue associated with this supplemental pipeline bond was recognized as a reduction of pipeline operating expense. See “Part I, Governmental Regulation -- Offshore Safety and Environmental Oversight – Decommissioning Requirements” for a discussion related to supplemental pipeline bonds. 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 (16) Income Taxes” of this Annual 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 Annual 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 (17) Earnings Per Share” for additional information related to EPS. Stock-Based Compensation Treasury Stock Reclassification New Pronouncements Issued But Not Yet Effective Income Taxes (Topic 740) (“ASU 2015-17”). In November 2015, FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent. Current GAAP requires deferred tax liabilities and assets to be separated into current and noncurrent. ASU 2015-17 is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period, and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We anticipate utilizing the majority of our current deferred tax assets prior to the effective date of ASU 2015-17. We do not anticipate adoption of this guidance to have a material effect on our consolidated balance sheets. Revenue from Contracts with Customers (“ASU 2014-09”). In May 2014, FASB issued ASU 2014-09, which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, FASB issued R which defers the effective date of ASU 2014-09 for all entities by one year. The effective date for public business entities is annual reporting periods beginning after December 15, 2017. Public business entities would apply the new revenue standard to interim reporting periods after December 15, 2017. As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods. This represents a one-year deferral from the original effective date. The new effective date guidance allows early adoption for all entities as of the original effective date (December 15, 2016). We are evaluating the impact that adoption of this guidance will have on the determination or reporting of our financial results. Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern for a one year period subsequent to the date of the financial statements. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements. Inventory (Topic 330): (“ASU 2015-11”). In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards. For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements. Interest – Imputation of Interest: ("ASU 2015-03"). In April 2015, FASB issued ASU 2015-03, which requires debt issue costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issue costs are not affected by ASU 2015-03. The amendments in this ASU are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. We plan to adopt this guidance beginning in the first quarter of 2016. Upon adoption, we anticipate reclassifying approximately $2.4 million of debt issue costs, net from log-term assets and reflecting this amount as a direct deduction from the carrying value of long-term debt. Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). In August 2015, FASB issued ASU 2015-15, which amends ASU 2015-03 by clarifying the presentation and subsequent measurement of debt issuance costs associated with lines of credit. These costs may be presented as an asset and amortized ratably over the term of the line of credit arrangement, regardless of whether there are outstanding borrowings on the arrangement. The effective date will be the first quarter of fiscal year 2016 and will be applied retrospectively. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements. Leases (Topic 842) (“ASU 2016-02”). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets. Other new pronouncements issued but not effective until after December 31, 2015 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	12 Months Ended
	Dec. 31, 2015
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 years ended December 31, 2015 and 2014 (and at December 31, 2015 and 2014), was as follows: Year Ended December 31, 2015 Year Ended December 31, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 221,586,156 $ 146,464 $ - $ 221,732,620 $ 388,434,838 $ 220,200 $ - $ 388,655,038 Less: cost of operations(1) (205,403,355 ) (45,931 ) (1,215,929 ) (206,665,215 ) (371,010,572 ) (483,262 ) (1,242,466 ) (372,736,300 ) Other non-interest income(2) - 312,500 660,000 972,500 - 270,833 - 270,833 Adjusted EBITDA 16,182,801 413,033 (555,929 ) 16,039,905 17,424,266 7,771 (1,242,466 ) 16,189,571 Less: JMA Profit Share(3) (5,820,329 ) - - (5,820,329 ) (3,602,581 ) - - (3,602,581 ) EBITDA $ 10,362,472 $ 413,033 $ (555,929 ) $ 13,821,685 $ 7,771 $ (1,242,466 ) Depletion, depreciation and amortization (1,647,586 ) (1,570,962 ) Interest expense, net (1,734,449 ) (844,850 ) Income before income taxes 6,837,541 10,171,178 Income tax benefit (expense) (2,434,302 ) 5,587,578 Net income $ 4,403,239 $ 15,758,756 Capital expenditures $ 12,244,658 $ - $ - $ 12,244,658 $ 1,720,156 $ - $ - $ 1,720,156 Identifiable assets $ 84,996,560 $ 2,338,107 $ 4,077,529 $ 91,412,196 $ 50,950,050 $ 3,028,719 $ 6,428,388 $ 60,407,157 (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 and the Grynberg Matter. See “Note (20) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this Annual Report for further discussion related to FLNG and Grynberg. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” and “Note (20) Commitments and Contingencies” of this Annual Report for further discussion of the Joint Marketing Agreement.

5. Prepaid Expenses and Other C

5. Prepaid Expenses and Other Current Assets	12 Months Ended
	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets consisted of the following: December 31, 2015 2014 Prepaid related party operating expenses $ 624,570 $ - Prepaid insurance 315,120 156,558 Unrealized hedging gains - 495,900 Prepaid professional fees - 104,000 Prepaid listing fees - 15,000 $ 939,690 $ 771,458

6. Inventories

6. Inventories	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Inventory consisted of the following: December 31, 2015 2014 HOBM $ 5,007,576 $ 124,176 Jet fuel 2,045,784 2,631,546 Naphtha 309,850 194,688 AGO 278,278 224,007 Chemicals 122,777 - Crude oil and condensate 19,041 19,041 Propane 17,860 - LPG mix 7,152 7,193 $ 7,808,318 $ 3,200,651

7. Property, Plant and Equipmen

7. Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, consisted of the following: December 31, 2015 2014 Refinery and facilities $ 40,195,928 $ 36,462,451 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 644,795 597,064 43,896,303 40,115,095 Less: Accumulated depletion, depreciation, and amortization (6,234,161 ) (4,586,575 ) 37,662,142 35,528,520 Construction in progress 11,179,670 1,842,555 $ 48,841,812 $ 37,371,075 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 $556,032 and $0 at December 31, 2015 and 2014, respectively.

8. Debt Issue Costs

8. Debt Issue Costs	12 Months Ended
	Dec. 31, 2015
Debt Issue Costs
Debt Issue Costs	Debt issuance costs are capitalized and amortized over the terms of the underlying loan using the effective-interest method. Debt issue costs totaled $2,441,218 and $690,980 at December 31, 2015 and 2014, respectively. Debt issue costs, net of accumulated amortization, totaled $2,391,482 and $479,737 at December 31, 2015 and 2014, respectively. Debt issue costs at December 31, 2015 related to loan agreements with Sovereign. Debt issue costs at December 31, 2014 related to a loan agreement with American First National Bank. Accumulated amortization totaled $49,736 and $211,244 at December 31, 2015 and 2014, respectively. Amortization expense, which is included in interest expense, was $544,607 and $33,799 for the years ended December 31, 2015 and 2014, respectively. Amortization expense for the year ended December 31, 2015 included $456,287 related to writing off debt issue costs associated with the refinance of debt owed to American First National Bank. See “Note (12) Long-Term Debt” of this Annual Report for additional disclosures related to the loan agreements with Sovereign and American First National Bank.

9. Accounts Payable, Related Pa

9. Accounts Payable, Related Party	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
Accounts Payable, Related Party	Accounts payable, related party totaled $300,000 and $1,174,168 at December 31, 2015 and 2014, respectively. Accounts payable, related party consisted of reimbursements and fees under the Operating Agreement and off-site storage tank leasing expense. Operating Agreement · Reimbursements . For management and operation of all properties excluding the Nixon Facility, LEH is reimbursed at cost for all reasonable expenses incurred while performing the services. Unsettled reimbursements to LEH are reflected within either prepaid expenses or accounts payable, related party in our consolidated balance sheets. Amounts reimbursed to LEH are reflected in the appropriate asset or expense accounts in our consolidated statements of income. · Fees . For management and operation of the Nixon Facility, LEH receives fees: (i) in the form of weekly payments from GEL TEX Marketing, LLC (“GEL”) not to exceed $750,000 per month, (ii) $0.25 for each barrel processed at the Nixon Facility up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iii) $2.50 for each barrel processed at the Nixon Facility in excess of 10,000 barrels per day determined on a monthly basis. In the normal course of business, we make estimates and assumptions related to amounts expensed for fees since actual amounts can vary depending upon production volumes. We then use the cumulative catch-up method to account for revisions in estimates, which may result in prepaid expenses or accounts payable, related party on our consolidated balance sheets. Amounts expensed as fees are reflected as refinery operating expenses in our consolidated statements of income. At December 31, 2015, we were in a prepaid position with respect to reimbursements and fees to LEH under the Operating Agreement. Prepaid related party operating expenses to LEH totaled $624,570 and $0 at December 31, 2015 and 2014, respectively. Accounts payable, related party to LEH totaled $0 and $1,174,168 at December 31, 2015 and 2014, respectively. For the years ended December 31, 2015 and 2014, refinery operating expenses totaled $11,683,658 (approximately $2.80 per barrel of throughput) and $10,698,023 (approximately $2.77 per barrel of throughput), respectively. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party. Short-Term Tank Lease Agreement

10. Accrued Expenses and Other

10. Accrued Expenses and Other Current Liabilities	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities consisted of the following: December 31, 2015 2014 Excise and income taxes payable $ 1,290,101 $ 1,228,411 Unearned revenue 781,859 252,500 Genesis JMA Profit Share payable 388,364 521,739 Unrealized hedging loss 183,400 - Other payable 157,714 149,962 Insurance 103,024 96,092 Board of director fees payable 86,429 345,000 Transportation and inspection - 190,000 $ 2,990,891 $ 2,783,704

11. Asset Retirement Obligation

11. Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Refinery and Facilities Pipelines and Facilities and Oil and Gas Properties Plugging and abandonment costs for oil and gas properties and pipelines are recorded as information becomes available to substantiate actual and/or probable costs. Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability. Liabilities settled and abandonment expense are recorded during the period incurred. For the years ended December 31, 2015 and 2014, we recognized $92,330 and $243,866, respectively, in liabilities settled. For the years ended December 31, 2015 and 2014, we did not incur any abandonment expense related to our oil and gas properties. AROs on a roll-forward basis were as follow: December 31, 2015 2014 Asset retirement obligations, at the beginning of the period $ 1,866,770 $ 1,597,661 New asset retirement obligations and adjustments 49 300,980 Liabilities settled (92,330 ) (243,866 ) Accretion expense 211,375 211,995 1,985,864 1,866,770 Less: current portion of asset retirement obligations (38,644 ) (85,846 ) Long-term asset retirement obligations, at the end of the period $ 1,947,220 $ 1,780,924 The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of certain of the Pipeline Assets. For additional information related to the WBI Transaction, see “Note (3) Significant Accounting Policies – Revenue Recognition – Deferred Revenue” and “Note (20) Commitments and Contingencies – Supplemental Pipeline Bonds” of this Annual Report.

12. Long-Term Debt

12. Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consisted of the following: December 31, 2015 2014 First Term Loan Due 2034 $ 24,643,081 $ - Second Term Loan Due 2034 10,000,000 - Notre Dame Debt 1,300,000 1,300,000 Term Loan Due 2017 924,969 1,638,898 Capital Leases 304,618 466,401 Refinery Note - 8,648,980 37,172,668 12,054,279 Less: current portion of long-term debt (1,934,932 ) (1,245,476 ) $ 35,237,736 $ 10,808,803 At December 31, 2015, our expected future long-term debt payments were as follow: Years Ending December 31, 2016 $ 1,934,932 2017 2,711,664 2018 1,180,953 2019 1,235,627 2020 1,309,735 Subsequent to 2020 28,799,757 $ 37,172,668 First Term Loan Due 2034 pursuant to a term loan in the principal amount of $25.0 million As a condition of the First Term Loan Due 2034, Jonathan P. 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 P. 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 a condition of the Second Term Loan Due 2034, Jonathan P. Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, we 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 year ended December 31, 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $16,667. There were no guaranty fees paid in 2014 related to the Second Term Loan Due 2034. 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 (9) Accounts Payable, Related Party” of this Annual Report for additional disclosures related to LEH. Proceeds of the Second Term Loan Due 2034 were used to refinance a $3.0 million bridge loan to Sovereign (see “Term Loan Due 2016” below). 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. Term Loan Due 2016 As a condition of the Term Loan Due 2016, Jonathan P. Carroll was required to guarantee r epayment 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 in June 2015, the holder of the Notre Dame Debt agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE first in favor of Sovereign as holder of the First Term Loan Due 2034 and second in favor of GEL. See “Note (20) Commitments and Contingencies” of this Annual Report for additional disclosures related to the Genesis Agreements. Term Loan Due 2017 As a condition of the Term Loan Due 2017, Jonathan P. 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 assets of LEH. See “Note (9) Accounts Payable, Related Party” of this Annual Report for additional disclosures related to LEH. Capital Leases The following is a summary of equipment held under long-term capital leases: December 31, 2015 2014 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598 At December 31, 2015, future minimum lease commitments under non-cancelable capital leases were as follow: Years Ending December 31, 2016 $ 177,031 2017 138,625 315,656 Less: amount representing interest (11,038 ) Present value of minimum lease payments $ 304,618 At December 31, 2015, the present value of minimum lease payments due within one year was $168,739. Refinery Note

13. Treasury Stock

13. Treasury Stock	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Treasury Stock	At December 31, 2015 and 2014, we had 150,000 shares of treasury stock.

14. Concentration of Risk

14. Concentration of Risk	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Concentration of Risk	Bank Accounts Key Supplier Significant Customers Refined Petroleum Product Sales Years Ended December 31, 2015 2014 LPG mix $ 1,253,826 0.6 % $ 705,664 0.2 % Naphtha 48,410,299 22.0 % 89,700,423 23.2 % Jet fuel 67,085,047 30.4 % 88,479,458 22.8 % NRLM - 0.0 % 62,729,476 16.2 % HOBM 46,936,751 21.3 % 49,662,414 12.8 % Reduced Crude 3,838,273 1.7 % - 0.0 % AGO 52,914,392 24.0 % 96,027,339 24.8 % $ 220,438,588 100.0 % $ 387,304,774 100.0 % We no longer produce transportation-related diesel fuel products. In May 2014, we ceased production of NRLM, a transportation-related diesel fuel product. In June 2014, we began producing HOBM, a non-transportation lubricant blend product. The shift in product slate from NRLM to HOBM was the result of the Environmental Protection Agency’s (the “EPA’s”) phased-in requirements for small refineries to reduce the sulfur content in transportation-related diesel fuel, such as NRLM, to a maximum of 15 ppm sulfur by June 1, 2014. “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s recently implemented fuel quality standards, and integration of such a unit generally requires additional permitting and significant capital upgrades. We can produce and sell a low sulfur diesel as a feedstock to other refineries and blenders in the U.S. and as a finished petroleum product to other countries.

15. Leases

15. Leases	12 Months Ended
	Dec. 31, 2015
Accounting Policies [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 years ended December 31, 2015 and 2014, rent expense totaled $142,604 and $98,876, respectively. At December 31, 2015, future minimum lease commitments that were non-cancelable under our office lease were as follow: Years Ending December 31, 2016 $ 129,417 2017 125,182 $ 254,599

16. Income Taxes

16. Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Benefit (Expense) Years Ended December 31, 2015 2014 Current: Federal $ (111,566 ) $ (64,258 ) State (169,867 ) (108,270 ) Deferred: Federal (2,152,869 ) 5,760,106 $ (2,434,302 ) $ 5,587,578 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. Effective Tax Rate 2015 2014 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 1.64 % 1.06 % Federal tax 0.01 % 0.63 % Change in valuation allowance 0.00 % (90.63 %) 35.65 % (54.94 %) Deferred Income Taxes NOL Carryforwards NOL carryforwards that remained available for future use 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 Total Pre-Ownership NOL Post-Ownership NOL Net Operating Loss Carryforward Balance at December 31, 2013 $ 12,087,459 $ 11,909,225 $ 23,996,684 Net operating losses - 236,564 236,564 Net operating loss carryforwards utilized (1,320,547 ) - (1,320,547 ) 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 Deferred Tax Assets and Liabilities . At December 31, 2015 and 2014, approximately $3.6 million and $5.8 million, respectively, of net deferred tax assets remained available for future use. Significant components of deferred tax assets and liabilities were as follow: December 31, 2015 2014 Deferred tax assets: Net operating loss and capital loss carryforwards $ 8,815,794 $ 10,067,144 Start-up costs (Nixon Facility) 1,510,699 1,648,036 Asset retirement obligations liability/deferred revenue 717,723 869,821 Unrealized hedges 62,356 - AMT credit and other 302,086 85,467 Total deferred tax assets 11,408,658 12,670,468 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges - (168,606 ) Basis differences in property and equipment (5,484,983 ) (4,425,318 ) Total deferred tax liabilities (5,531,099 ) (4,640,040 ) Deferred tax assets, net 5,877,559 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,607,237 $ 5,760,106 Deferred tax assets (liabilities) on a current and noncurrent basis were as follow: December 31, 2015 2014 Current deferred tax assets $ 3,486,746 $ (168,237 ) Noncurrent deferred tax assets, net 2,390,813 8,198,665 Deferred tax assets, net 5,877,559 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,607,237 $ 5,760,106 Valuation Allowance . As of each reporting date, management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets. As of December 31, 2015 and 2014, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $3.6 million and $5.8 million, respectively, were realizable, and as a result, reflected a valuation allowance accordingly. 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 income for the years ended December 31, 2015 and 2014. Furthermore, none of our federal and state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. As of December 31, 2015, calendar years 2012 and later remain subject to examination by the IRS and fiscal years 2011 and later remain subject to examination by the state of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.

17. Earnings Per Share

17. Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	The following table provides reconciliation between basic and diluted income per share: Years Ended December 31, 2015 2014 Net income $ 4,403,239 $ 15,758,756 Basic and diluted income per share $ 0.42 $ 1.51 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,451,832 10,441,464 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the years ended December, 2015 and 2014 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

18. Fair Value Measurement

18. Fair Value Measurement	12 Months Ended
	Dec. 31, 2015
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 short and long-term debt at December 31, 2015 and 2014 was $37,172,668 and $12,054,279, 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 December 31, 2015 and 2014 and the basis for the measurement: Fair Value Measurement at December 31, 2015 Using Financial assets (liabilities): Carrying Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ (183,400 ) $ (183,400 ) $ - $ - Fair Value Measurement at December 31, 2014 Using Financial assets (liabilities): Carrying Value at December 31, 2014 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 495,900 $ 495,900 $ - $ - Carrying amounts of commodity contracts executed by Genesis are reflected as other current assets or other current liabilities in our consolidated balance sheets.

19. Inventory Risk Management

19. Inventory Risk Management	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Inventory Risk Management	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 these 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 income. 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 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 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 contracts. As of December 31, 2015, 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 barrels): Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2015 2016 2017 Refined petroleum products and crude oil - net short positions 235,000 - - The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at December 31, 2015 and 2014: Fair Value December 31, Asset Derivatives Balance Sheets Location 2015 2014 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ (183,400 ) $ 495,900 The following table provides the effect of derivative instruments in our consolidated statements of income for the years ended December 31, 2015 and 2014: Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2015 2014 Commodity contracts Cost of refined products sold $ 3,730,613 $ 3,816,871

20. Commitments and Contingenci

20. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Operating Agreement Genesis Agreements Crude Supply Agreement . Under the Crude Supply Agreement, GEL is our exclusive supplier of crude oil and condensate. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to us pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described above. In addition, GEL has a first right of refusal to use three petroleum storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply 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 Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply 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; and . Under the Joint Marketing Agreement, we, together with GEL, jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. GEL is responsible for all product transportation scheduling; we are responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. All payments for the sale of output produced at the Nixon Facility are made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement). As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, certain aspects related to the distribution of Gross Profits under the Joint Marketing Agreement no longer apply. Key applicable provisions are as follows: - 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 Annual 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 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 December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. At December 31, 2014, we maintained approximately $1.6 million in credit and cash-backed rights-of-way bonds issued to the BOEM. In December 2014, we completed work to abandon-in-place the pipeline associated with Right-of-Way Number OCS-G 08606. As a result, in November 2015, the BOEM released approximately $0.7 million in cash collateral backing this supplemental pipeline bond. Financing Agreements Grynberg Settlement Agreement (the “Grynberg Settlement Agreement”) dated October 2015. The Grynberg Settlement Agreement provided for a settlement in the amount of $725,073 (the “Settlement Amount”). The Settlement Amount represented 50% of a $1,371,723 November 2006 summary judgment in our favor plus 1.5% interest. We received the Settlement Amount in October 2015. Based on management’s assessment, we recognized a net gain of $660,000 in other income from the Grynberg Matter (the Settlement Amount less additional legal fees of approximately $65,000). Nixon Facility Expansion have made and continue to make capital and efficiency improvements to the Nixon Facility. As a result, we have incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and construction of additional petroleum storage tanks. Legal Matters Health, Safety and Environmental Matters

3. Significant Accounting Pol27

3. Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of presentation	We have prepared our audited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation.
Use of Estimates	Use of Estimates
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash	Restricted Cash
Accounts Receivable, Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
Inventory	Inventory
Derivatives	Derivatives Although these commodity futures contracts are not subject to hedge accounting treatment under FASB 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 income. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of income using mark-to-market accounting. See “Note (18) Fair Value Measurement” and “Note (19) Inventory Risk Management” of this Annual Report for additional disclosures related to derivatives.
Property and Equipment	Property and Equipment Refinery and Facilities . Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances. 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 income. 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 the years ended December 31, 2015 and 2014. Pipelines and Facilities . We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. Oil and Gas Properties . We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the years ended December 31, 2015 and 2014. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired at December 31, 2012. Construction in Progress . Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service. See “Note (7) Property, Plant and Equipment, Net” of this Annual 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
Debt Issue Costs	Debt Issue Costs
Revenue Recognition	Revenue Recognition Refined Petroleum Products Revenue . We sell jet fuel in nearby markets, and our intermediate products, including liquefied petroleum gas, naphtha, HOBM, and atmospheric gas oil (“AGO”), to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. 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 . Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. Easement Revenue . Land easement revenue is recognized monthly as earned and is included in other income. Pipeline Transportation Revenue . Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline. Deferred Revenue . In February 2014, we entered into an Asset Sale Agreement (the “Purchase Agreement”) with WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), whereby we reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline, and the Omega Pipeline (the “Pipeline Assets”) effective in October 2013. Prior to the Purchase Agreement, we owned approximately 83% of the Pipeline Assets. Pursuant to the Purchase Agreement, WBI paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for our benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure. In December 2014, we completed work to abandon-in-place the pipeline associated with Right-of-Way Number OCS-G 08606. In November 2015, the Bureau of Environmental Management released $645,000 in cash collateral backing this supplemental pipeline bond. The remaining $422,373 of deferred revenue associated with this supplemental pipeline bond was recognized as a reduction of pipeline operating expense. See “Part I, Governmental Regulation -- Offshore Safety and Environmental Oversight – Decommissioning Requirements” for a discussion related to supplemental pipeline bonds.
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 (16) Income Taxes” of this Annual 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 Annual 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 (17) Earnings Per Share” for additional information related to EPS.
Stock Based Compensation	Stock-Based Compensation
Treasury Stock	Treasury Stock
Reclassification	Reclassification
New Pronouncements Issued but Not Yet Effective	New Pronouncements Issued But Not Yet Effective Income Taxes (Topic 740) Revenue from Contracts with Customers In August 2015, FASB issued R evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern Inventory (Topic 330): Simplifying the Measurement of Inventory Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements Leases (Topic 842) Other new pronouncements issued but not effective until after December 31, 2015 are not expected to have a material impact on our financial position, results of operations or liquidity.

4. Business Segment Informati28

4. Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Business segment reporting	Business segment information for the years ended December 31, 2015 and 2014 (and at December 31, 2015 and 2014), was as follows: Year Ended December 31, 2015 Year Ended December 31, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 221,586,156 $ 146,464 $ - $ 221,732,620 $ 388,434,838 $ 220,200 $ - $ 388,655,038 Less: cost of operations(1) (205,403,355 ) (45,931 ) (1,215,929 ) (206,665,215 ) (371,010,572 ) (483,262 ) (1,242,466 ) (372,736,300 ) Other non-interest income(2) - 312,500 660,000 972,500 - 270,833 - 270,833 Adjusted EBITDA 16,182,801 413,033 (555,929 ) 16,039,905 17,424,266 7,771 (1,242,466 ) 16,189,571 Less: JMA Profit Share(3) (5,820,329 ) - - (5,820,329 ) (3,602,581 ) - - (3,602,581 ) EBITDA $ 10,362,472 $ 413,033 $ (555,929 ) $ 13,821,685 $ 7,771 $ (1,242,466 ) Depletion, depreciation and amortization (1,647,586 ) (1,570,962 ) Interest expense, net (1,734,449 ) (844,850 ) Income before income taxes 6,837,541 10,171,178 Income tax benefit (expense) (2,434,302 ) 5,587,578 Net income $ 4,403,239 $ 15,758,756 Capital expenditures $ 12,244,658 $ - $ - $ 12,244,658 $ 1,720,156 $ - $ - $ 1,720,156 Identifiable assets $ 84,996,560 $ 2,338,107 $ 4,077,529 $ 91,412,196 $ 50,950,050 $ 3,028,719 $ 6,428,388 $ 60,407,157 (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 and the Grynberg Matter. See “Note (20) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this Annual Report for further discussion related to FLNG and Grynberg. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” and “Note (20) Commitments and Contingencies” of this Annual Report for further discussion of the Joint Marketing Agreement.

5. Prepaid Expenses and Other29

5. Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Liabilities extinguished
Prepaid balances	Prepaid expenses and other current assets consisted of the following: December 31, 2015 2014 Prepaid related party operating expenses $ 624,570 $ - Prepaid insurance 315,120 156,558 Unrealized hedging gains - 495,900 Prepaid professional fees - 104,000 Prepaid listing fees - 15,000 $ 939,690 $ 771,458

6. Inventories (Tables)

6. Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories balances	Inventory consisted of the following: December 31, 2015 2014 HOBM $ 5,007,576 $ 124,176 Jet fuel 2,045,784 2,631,546 Naphtha 309,850 194,688 AGO 278,278 224,007 Chemicals 122,777 - Crude oil and condensate 19,041 19,041 Propane 17,860 - LPG mix 7,152 7,193 $ 7,808,318 $ 3,200,651

7. Property, Plant and Equipm31

7. Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property and equipment	Property, plant and equipment, net, consisted of the following: December 31, 2015 2014 Refinery and facilities $ 40,195,928 $ 36,462,451 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 644,795 597,064 43,896,303 40,115,095 Less: Accumulated depletion, depreciation, and amortization (6,234,161 ) (4,586,575 ) 37,662,142 35,528,520 Construction in progress 11,179,670 1,842,555 $ 48,841,812 $ 37,371,075

10. Accrued Expenses and Othe32

10. Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Accrued Expenses And Other Current Liabilities Tables
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities consisted of the following: December 31, 2015 2014 Excise and income taxes payable $ 1,290,101 $ 1,228,411 Unearned revenue 781,859 252,500 Genesis JMA Profit Share payable 388,364 521,739 Unrealized hedging loss 183,400 - Other payable 157,714 149,962 Insurance 103,024 96,092 Board of director fees payable 86,429 345,000 Transportation and inspection - 190,000 $ 2,990,891 $ 2,783,704

11. Asset Retirement Obligati33

11. Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	AROs on a roll-forward basis were as follow: December 31, 2015 2014 Asset retirement obligations, at the beginning of the period $ 1,866,770 $ 1,597,661 New asset retirement obligations and adjustments 49 300,980 Liabilities settled (92,330 ) (243,866 ) Accretion expense 211,375 211,995 1,985,864 1,866,770 Less: current portion of asset retirement obligations (38,644 ) (85,846 ) Long-term asset retirement obligations, at the end of the period $ 1,947,220 $ 1,780,924

12. Long-Term Debt (Tables)

12. Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long Term Debt	Long-term debt consisted of the following: December 31, 2015 2014 First Term Loan Due 2034 $ 24,643,081 $ - Second Term Loan Due 2034 10,000,000 - Notre Dame Debt 1,300,000 1,300,000 Term Loan Due 2017 924,969 1,638,898 Capital Leases 304,618 466,401 Refinery Note - 8,648,980 37,172,668 12,054,279 Less: current portion of long-term debt (1,934,932 ) (1,245,476 ) $ 35,237,736 $ 10,808,803
Schedule of future long-term debt payments	At December 31, 2015, our expected future long-term debt payments were as follow: Years Ending December 31, 2016 $ 1,934,932 2017 2,711,664 2018 1,180,953 2019 1,235,627 2020 1,309,735 Subsequent to 2020 28,799,757 $ 37,172,668
Schedule of long-term capital leases	The following is a summary of equipment held under long-term capital leases: December 31, 2015 2014 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598
Future minimum lease commitments under non-cancelable capital leases	At December 31, 2015, future minimum lease commitments under non-cancelable capital leases were as follow: Years Ending December 31, 2016 $ 177,031 2017 138,625 315,656 Less: amount representing interest (11,038 ) Present value of minimum lease payments $ 304,618

14. Concentration of Risk (Tabl

14. Concentration of Risk (Tables)	12 Months Ended
	Dec. 31, 2015
Concentration Of Risk Tables
Percentages of all refined petroleum products sales to total sales	Refined Petroleum Product Sales Years Ended December 31, 2015 2014 LPG mix $ 1,253,826 0.6 % $ 705,664 0.2 % Naphtha 48,410,299 22.0 % 89,700,423 23.2 % Jet fuel 67,085,047 30.4 % 88,479,458 22.8 % NRLM - 0.0 % 62,729,476 16.2 % HOBM 46,936,751 21.3 % 49,662,414 12.8 % Reduced Crude 3,838,273 1.7 % - 0.0 % AGO 52,914,392 24.0 % 96,027,339 24.8 % $ 220,438,588 100.0 % $ 387,304,774 100.0 %

15. Leases (Tables)

15. Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Future minimum lease payments	At December 31, 2015, future minimum lease commitments that were non-cancelable under our office lease were as follow: Years Ending December 31, 2016 $ 129,417 2017 125,182 $ 254,599

16. Income Taxes (Tables)

16. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Income Tax Benefit (Expense) Years Ended December 31, 2015 2014 Current: Federal $ (111,566 ) $ (64,258 ) State (169,867 ) (108,270 ) Deferred: Federal (2,152,869 ) 5,760,106 $ (2,434,302 ) $ 5,587,578
Effective tax rate	Effective Tax Rate 2015 2014 Expected tax rate 34.00 % 34.00 % Permanent differences 0.00 % 0.00 % State tax 1.64 % 1.06 % Federal tax 0.01 % 0.63 % Change in valuation allowance 0.00 % (90.63 %) 35.65 % (54.94 %)
NOL carryforwards	NOL carryforwards that remained available for future use were as follows: Net Operating Loss Carryforward Total Pre-Ownership NOL Post-Ownership NOL Net Operating Loss Carryforward Balance at December 31, 2013 $ 12,087,459 $ 11,909,225 $ 23,996,684 Net operating losses - 236,564 236,564 Net operating loss carryforwards utilized (1,320,547 ) - (1,320,547 ) 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
Deferred tax assets and deferred tax liabilities	Deferred Tax Assets and Liabilities . At December 31, 2015 and 2014, approximately $3.6 million and $5.8 million, respectively, of net deferred tax assets remained available for future use. Significant components of deferred tax assets and liabilities were as follow: December 31, 2015 2014 Deferred tax assets: Net operating loss and capital loss carryforwards $ 8,815,794 $ 10,067,144 Start-up costs (Nixon Facility) 1,510,699 1,648,036 Asset retirement obligations liability/deferred revenue 717,723 869,821 Unrealized hedges 62,356 - AMT credit and other 302,086 85,467 Total deferred tax assets 11,408,658 12,670,468 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges - (168,606 ) Basis differences in property and equipment (5,484,983 ) (4,425,318 ) Total deferred tax liabilities (5,531,099 ) (4,640,040 ) Deferred tax assets, net 5,877,559 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,607,237 $ 5,760,106
Current and noncurrent deferred tax assets (liabilities)	Deferred tax assets (liabilities) on a current and noncurrent basis were as follow: December 31, 2015 2014 Current deferred tax assets $ 3,486,746 $ (168,237 ) Noncurrent deferred tax assets, net 2,390,813 8,198,665 Deferred tax assets, net 5,877,559 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,607,237 $ 5,760,106

17. Earnings Per Share (Tables)

17. Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per share	The following table provides reconciliation between basic and diluted income per share: Years Ended December 31, 2015 2014 Net income $ 4,403,239 $ 15,758,756 Basic and diluted income per share $ 0.42 $ 1.51 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,451,832 10,441,464

18. Fair Value Measurement (Tab

18. Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2015
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 December 31, 2015 and 2014 and the basis for the measurement: Fair Value Measurement at December 31, 2015 Using Financial assets (liabilities): Carrying Value at December 31, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ (183,400 ) $ (183,400 ) $ - $ - Fair Value Measurement at December 31, 2014 Using Financial assets (liabilities): Carrying Value at December 31, 2014 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 495,900 $ 495,900 $ - $ -

19. Inventory Risk Management (

19. Inventory Risk Management (Tables)	12 Months Ended
	Dec. 31, 2015
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 barrels): Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2015 2016 2017 Refined petroleum products and crude oil - net short positions 235,000 - -
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 December 31, 2015 and 2014: Fair Value December 31, Asset Derivatives Balance Sheets Location 2015 2014 Commodity contracts Prepaid expenses and other current assets (accrued expenses and other current liabilities) $ (183,400 ) $ 495,900
Effect of derivative instruments	The following table provides the effect of derivative instruments in our consolidated statements of income for the years ended December 31, 2015 and 2014: Gain (Loss) Recognized Years Ended December 31, Derivatives Statements of Operations Location 2015 2014 Commodity contracts Cost of refined products sold $ 3,730,613 $ 3,816,871

3. Significant Accounting Pol41

3. Significant Accounting Policies (Details Narrative) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Cash and cash equivalents	$ 1,853,875	$ 1,293,233	$ 434,717
Restricted cash	3,175,299	1,008,514
Restricted cash, noncurrent	15,616,478	0
Allowance for doubtful accounts	139,868	0
Trade name	$ 303,346	$ 303,346

4. Business Segment Informati42

4. Business Segment Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Revenue from operations		$ 221,732,620	$ 388,655,123
Less: cost of operations	[1]	(206,665,215)	(372,736,300)
Other non-interest income	[2]	972,500	270,833
Adjusted EBITDA		16,039,905	16,189,571
Less: JMA Profit Share	[3]	(5,820,329)	(3,602,581)
Depletion, depreciation and amortization		(1,647,586)	(1,570,962)
Interest expense, net		(1,734,449)	(844,850)
Income before income taxes		6,837,541	10,171,178
Income tax benefit (expense)		(2,434,302)	5,587,578
Net income		4,403,239	15,758,756
Capital expenditures		12,244,658	1,720,156
Identifiable assets		91,412,196	60,407,157
Segment Refinery Operations [Member]
Revenue from operations		221,586,156	388,434,838
Less: cost of operations	[1]	$ (205,403,355)	$ (371,010,572)
Other non-interest income	[2]
Adjusted EBITDA		$ 16,182,801	$ 17,424,266
Less: JMA Profit Share	[3]	(5,820,329)	(3,602,581)
EBITDA		10,362,472	13,821,685
Capital expenditures		12,244,658	1,720,156
Identifiable assets		84,996,560	50,950,050
Segment Pipeline Transportation [Member]
Revenue from operations		146,464	220,200
Less: cost of operations	[1]	(45,931)	(483,262)
Other non-interest income	[2]	312,500	270,833
Adjusted EBITDA		$ 413,033	$ 7,771
Less: JMA Profit Share	[3]
EBITDA		$ 413,033	$ 7,771
Capital expenditures
Identifiable assets		$ 2,338,107	$ 3,028,719
Corporate and Other
Revenue from operations
Less: cost of operations	[1]	$ (1,215,929)	$ (1,242,466)
Other non-interest income	[2]	660,000
Adjusted EBITDA		$ (555,929)	$ (1,242,466)
Less: JMA Profit Share	[3]
EBITDA		$ (555,929)	$ (1,242,466)
Capital expenditures
Identifiable assets		$ 4,077,529	$ 6,428,388
[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 and the Grynberg Matter. See "Note (20) Commitments and Contingencies - FLNG Master Easement Agreement and Grynberg Settlement Agreement" of this Annual Report for further discussion related to FLNG and Grynberg.
[3]	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See "Part II' Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Relationship with Genesis" and "Note (20) Commitments and Contingencies" of this Annual Report for further discussion of the Joint Marketing Agreement'.

5. Prepaid Expenses and Other43

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Prepaid Expenses And Other Current Assets Details
Prepaid related party operating expenses	$ 624,570
Prepaid insurance	$ 315,120	$ 156,558
Unrealized hedging gains		495,900
Prepaid professional fees		104,000
Prepaid listing fees		15,000
Prepaid Expenses, Net	$ 939,690	$ 771,458

6. Inventories (Details)

6. Inventories (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
HOBM	$ 5,007,576	$ 124,176
Jet fuel	2,045,784	2,631,546
Naphtha	309,850	194,688
AGO	278,278	$ 224,007
Chemicals	122,777
Crude oil and condensate	19,041	$ 19,041
Propane	17,860
LPG mix	7,152	$ 7,193
Inventories, Net	$ 7,808,318	$ 3,200,651

7. Property, Plant and Equipm45

7. Property, Plant and Equipment, Net (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment Net Details
Refinery and facilities	$ 40,195,928	$ 36,462,451
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	644,795	597,064
Property, Plant and Equipment, Gross	43,896,303	40,115,095
Less: Accumulated depletion, depreciation, and amortization	(6,234,161)	(4,586,575)
Property, Plant and Equipment less depreciation	37,662,142	35,528,520
Construction in Progress	11,179,670	1,842,555
Property, Plant and Equipment, Net	48,841,812	37,371,075
Interest Costs Capitalized	$ 556,032	$ 0

8. Debt Issue Costs (Details Na

8. Debt Issue Costs (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Issue Costs
Debt issuance costs	$ 2,441,218	$ 690,980
Accumulated amortization	49,736	211,244
Debt issue costs, net	2,391,482	479,737
Interest expense including Amortization expense	544,607	$ 33,799
Refinancing debt owed to American First National Bank	$ 456,287

9. Accounts Payable, Related 47

9. Accounts Payable, Related Party (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Expense for service	$ 11,683,658	$ 10,698,023
Prepaid related party operating expenses	624,570
Accounts payable, related party	300,000	$ 1,174,168
LEH [Member]
Accounts payable, related party	$ 0	$ 1,174,168

10. Accrued Expenses and Othe48

10. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Accrued Expenses And Other Current Liabilities Details
Excise and income taxes payable	$ 1,290,101	$ 1,228,411
Unearned revenue	781,859	252,500
Genesis JMA Profit Share payable	388,364	$ 521,739
Unrealized hedging loss	183,400
Other payable	157,714	$ 149,962
Insurance	103,024	96,092
Board of director fees payable	$ 86,429	345,000
Transportation and inspection		190,000
Accrued Expenses and Other Current Liabilities, Net	$ 2,990,891	$ 2,783,704

11. Asset Retirement Obligati49

11. Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations Details
Asset retirement obligations, at the beginning of the period	$ 1,866,770	$ 1,597,661
New asset retirement obligations and adjustments	49	300,980
Liabilities settled	(92,330)	(243,866)
Accretion expense	211,375	211,995
Total	1,985,864	1,866,770
Less: current portion of asset retirement obligations	(38,644)	(85,846)
Long-term asset retirement obligations, at the end of the period	$ 1,947,220	$ 1,780,924

11. Asset Retirement Obligati50

11. Asset Retirement Obligations (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations Details Narrative
Liabilities settled recognized	$ 92,330	$ 243,866
Abandonment expense	$ 0	$ 0

12. Long-Term Debt (Details)

12. Long-Term Debt (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
First Term Loan Due 2034	$ 24,643,081
Second Term Loan Due 2034	10,000,000
Notre Dame Debt	1,300,000	$ 1,300,000
Term Loan Due 2017	924,969	1,638,898
Capital Leases	$ 304,618	466,401
Refinery Note		8,648,980
Total	$ 37,172,668	12,054,279
Less: current portion of long-term debt	(1,934,932)	(1,245,476)
Long term debt	$ 35,237,736	$ 10,808,803

12. Long-Term Debt (Details 1)

12. Long-Term Debt (Details 1)	Dec. 31, 2015USD ($)
Long-Term Debt Details 1
2,016	$ 1,934,932
2,017	2,711,664
2,018	1,180,953
2,019	1,235,627
2,020	1,309,735
Subsequent to 2020	28,799,757
Long Term Debt Payment, Net	$ 37,172,668

12. Long-Term Debt (Details 2)

12. Long-Term Debt (Details 2) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt Details 2
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation
Capital lease obligation	$ 538,598	$ 538,598

12. Long-Term Debt (Details 3)

12. Long-Term Debt (Details 3)	Dec. 31, 2015USD ($)
Long-term Debt Details 3
2,016	$ 177,031
2,017	138,625
Total future minimum lease payments	315,656
Less: amount representing interest	(11,038)
Present value of minimum lease payments	$ 304,618

12. Long-Term Debt (Details Nar

12. Long-Term Debt (Details Narrative) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Principal balance outstanding	$ 35,237,736	$ 10,808,803
Capital Leases	304,618	466,401
Interest accrued on capital leases	0	2,612
Term Loan Due 2034 [Member]
Principal balance outstanding	24,643,081	0
Interest accrued	34,883	0
Guaranty fees	265,518	0
Second Term Loan Due 2034 [Member]
Principal balance outstanding	10,000,000	0
Interest accrued	39,194	0
Term Loan Due 2016 [Member]
Principal balance outstanding	0
Interest accrued	0
Guaranty fees	26,500
Notre Dame Debt [Member]
Principal balance outstanding	0	1,300,000
Interest accrued	0	1,482,801
Guaranty fees	26,500
Term Loan Due 2017 [Member]
Principal balance outstanding	1,300,000	924,969
Interest accrued	1,274,789	$ 4,779
Capital Leases [Member]
Principal balance outstanding	1,638,898
Interest accrued	$ 8,470

13. Treasury Stock (Details Nar

13. Treasury Stock (Details Narrative) - shares	Dec. 31, 2015	Dec. 31, 2014
Treasury Stock Details Narrative
Treasury stock	150,000	150,000

14. Concentration of Risk (Deta

14. Concentration of Risk (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Total refined petroleum product sales	$ 220,438,588	$ 387,304,774
Concentration Risk	100.00%	100.00%
LPG mix [Member]
Total refined petroleum product sales	$ 1,253,826	$ 705,664
Concentration Risk	0.60%	0.20%
Naphtha
Total refined petroleum product sales	$ 48,410,299	$ 89,700,423
Concentration Risk	22.00%	23.20%
Jet Fuel [Member]
Total refined petroleum product sales	$ 67,085,047	$ 88,479,458
Concentration Risk	30.40%	22.80%
NRLM [Member]
Total refined petroleum product sales		$ 62,729,476
Concentration Risk	0.00%	16.20%
HOBM [Member]
Total refined petroleum product sales	$ 46,936,751	$ 49,662,414
Concentration Risk	21.30%	12.80%
Reduced crude [Member]
Total refined petroleum product sales	$ 3,838,273
Concentration Risk	1.70%	0.00%
AGO [Member]
Total refined petroleum product sales	$ 52,914,392	$ 96,027,339
Concentration Risk	24.00%	24.80%

14. Concentration of Risk (De58

14. Concentration of Risk (Details Narrative ) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250,000	$ 250,000
Excess of the FDIC insurance limit	$ 19,594,883	$ 1,113,977
Sales Revenue [Member] | Three customers [Member]
Concentration Risk	56.00%
Sales Revenue [Member] | Five customers [Member]
Concentration Risk		89.00%
Account receivable [Member] | Three customers [Member]
Accounts receivable	$ 300,000
Account receivable [Member] | Five customers [Member]
Accounts receivable		$ 6,400,000

15. Leases (Details)

15. Leases (Details)	Dec. 31, 2015USD ($)
Leases Details 1
2,016	$ 129,417
2,017	125,182
Leases Futurre Minimum Payment, Net	$ 254,599

15. Leases (Details Narrative)

15. Leases (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Leases Details Narrative
Rent expense	$ 142,604	$ 98,876

16. Income Taxes (Details)

16. Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal	$ (111,566)	$ (64,258)
State	(169,867)	(108,270)
Deferred:
Federal	(2,152,869)	5,760,106
Income tax benefit (expense)	$ (2,434,302)	$ 5,587,578

16. Income Taxes (Details 1)

16. Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes Details 1
Expected tax rate	34.00%	34.00%
Permanent differences	0.00%	0.00%
State tax	1.64%	1.06%
Federal tax	0.01%	0.63%
Change in valuation allowance	0.00%	(90.63%)
Expected tax rate Continuing Operations	35.65%	(54.94%)

16. Income Taxes (Details 3)

16. Income Taxes (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Balance	$ 22,912,701	$ 23,996,684
Net operating losses generated post-acquisition		236,564
Net operating loss carryforward utilized	(3,681,311)	(1,320,547)
Balance	19,231,390	22,912,701
Pre-Ownership Change [Member]
Balance	10,766,912	$ 12,087,459
Net operating losses generated post-acquisition
Net operating loss carryforward utilized	(1,152,463)	$ (1,320,547)
Balance	9,614,449	10,766,912
Post-Ownership Change [Member]
Balance	236,564	11,909,225
Net operating losses generated post-acquisition		$ 236,564
Net operating loss carryforward utilized	(2,528,848)
Balance	$ 9,616,941	$ 236,564

16. Income Taxes (Details 4)

16. Income Taxes (Details 4) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 8,815,794	$ 10,067,144
Start-up costs (Nixon Facility)	1,510,699	1,648,036
Asset retirement obligations liability/deferred revenue	717,723	$ 869,821
Unrealized hedges	62,356
AMT credit and other	302,086	$ 85,467
Total deferred tax assets	11,408,658	12,670,468
Deferred tax liabilities:
Fair market value adjustments	$ (46,116)	(46,116)
Unrealized hedges		(168,606)
Basis differences in property and equipment	$ (5,484,983)	(4,425,318)
Total deferred tax liabilities	(5,531,099)	(4,640,040)
Deferred tax assets, net	5,877,559	8,030,428
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 3,607,237	$ 5,760,106

16. Income Taxes (Details 5)

16. Income Taxes (Details 5) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Taxes Details 5
Current deferred tax assets	$ 3,486,746	$ (168,237)
Noncurrent deferred tax assets, net	2,390,813	8,198,665
Deferred tax assets, net	5,877,559	8,030,428
Less: valuation allowance	2,270,322	2,270,322
Deferred tax assets and liabilities, net	$ 3,607,237	$ 5,760,106

16. Income Taxes (Details Narra

16. Income Taxes (Details Narrative) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Taxes Details 1
Deferred Tax Assets	$ 3,600,000	$ 5,800,000

17. Earnings per share (Details

17. Earnings per share (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net income	$ 4,403,239	$ 15,758,756
Basic and diluted income per share	$ 0.42	$ 1.51
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,451,832	10,441,464

18. Fair Value Measurement (Det

18. Fair Value Measurement (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Financial liabilties:
Commodity contracts	$ (183,400)	$ 495,900
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
Financial liabilties:
Commodity contracts	$ (183,400)	$ 495,900
Significant Other Observable Inputs (Level 2)
Financial liabilties:
Commodity contracts
Significant Unobservable Inputs (Level 3)
Financial liabilties:
Commodity contracts

19. Inventory Risk Management69

19. Inventory Risk Management (Details) - Refined products - net short (long) positions	Dec. 31, 2015shares
Volume in Thousands of barrels
Notional Contract Volumes 2015	235,000
Notional Contract Volumes 2016
Notional Contract Volumes 2017

19. Inventory Risk Management70

19. Inventory Risk Management (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Inventory Risk Management Details 1
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ (183,400)	$ 495,900
Cost of refined products sold	$ 3,730,613	$ 3,816,871

20. Commitments and Contingen71

20. Commitments and Contingencies (Details Narrative) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Credit and cash backed rights of way bonds issued to the BOEM	$ 900,000	$ 1,600,000