Blue Dolphin Energy (BDCO) 10-K31 Mar 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Mar. 31, 2015
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793306
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
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		10,449,444
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
Entity Public Float	$9,588,038

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$1,293,233	$434,717
Restricted cash	1,008,514	327,388
Accounts receivable	8,340,303	13,487,106
Prepaid expenses and other current assets	771,458	333,683
Deposits	68,498	1,219,660
Inventory	3,200,651	4,686,399
Total current assets	14,682,657	20,488,953
Total property and equipment, net	37,371,075	36,388,666
Surety bonds	1,642,000
Debt issue costs, net	479,737	498,536
Trade name	303,346	303,346
Deferred tax assets, net	5,928,342
TOTAL ASSETS	60,407,157	57,679,501
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	12,370,179	20,783,541
Accounts payable, related party	1,174,168	3,659,340
Notes payable		11,884
Asset retirement obligations, current portion	85,846	107,388
Accrued expenses and other current liabilities	2,783,704	1,600,444
Interest payable, current portion	56,039	40,272
Long-term debt, current portion	1,245,476	2,215,918
Deferred tax liabilities	168,236
Total current liabilities	17,883,648	28,418,787
Asset retirement obligations, net of current portion	1,780,924	1,490,273
Deferred revenues and expenses	691,525
Long-term debt, net of current portion	10,808,803	13,889,349
Long-term interest payable, net of current portion	1,274,789	1,767,381
Total long-term liabilities	14,556,041	17,147,003
TOTAL LIABILITIES	32,439,689	45,565,790
Commitments and contingencies (Note 22)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized;10,599,444 and 10,580,973shares issued at December 31, 2014 and 2013, respectively)	105,995	105,810
Additional paid-in capital	36,718,781	36,623,965
Accumulated deficit	-8,057,308	-23,816,064
Treasury stock, 150,000 shares at cost	-800,000	-800,000
Total stockholders' equity	27,967,468	12,113,711
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$60,407,157	$57,679,501

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
STOCKHOLDERS' EQUITY
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,599,444	10,580,973

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
Consolidated Statements of Operations (USD $)	Dec. 31, 2014	Dec. 31, 2013
REVENUE FROM OPERATIONS
Refined product sales	$387,304,774	$409,239,747
Pipeline operations	220,200	303,122
Oil and gas sales		200
Total revenue from operations	387,524,974	409,543,069
COST OF OPERATIONS
Cost of refined products sold	363,762,292	399,101,182
Refinery operating expenses	10,698,023	10,673,722
Pipeline operating expenses	208,037	163,163
Lease operating expenses	26,428	67,923
General and administrative expenses	1,427,707	1,794,053
Depletion, depreciation and amortization	1,570,962	1,342,563
Abandonment expense		63,767
Accretion expense	211,995	112,686
Total cost of operations	377,905,444	413,319,059
Income (loss) from operations	9,619,530	-3,775,990
OTHER INCOME (EXPENSE)
Tank rental and easement revenue	1,400,898	1,155,064
Interest and other income	47,522	3,105
Interest expense	-892,372	-1,100,053
Loss on disposal of property and equipment	-4,400
Total other income	551,648	58,116
Income (loss) before income taxes	10,171,178	-3,717,874
Income tax benefit (expense)	5,587,578	-89,255
Net income (loss)	$15,758,756	($3,807,129)
Income (loss) per common share
Basic	$1.51	($0.36)
Diluted	$1.51	($0.36)
Weighted average number of common shares outstanding:
Basic	10,441,464	10,445,883
Diluted	10,441,464	10,445,883

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
Consolidated Statements of Cash Flows (USD $)	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES
Net income (loss)	$15,758,756	($3,807,129)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,570,962	1,342,563
Unrealized gain on derivatives	-488,950	-143,050
Deferred taxes	-5,760,106
Amortization of debt issue costs	33,799	33,800
Amortization of intangible assets		9,463
Accretion expense	211,995	112,686
Abandonment costs incurred		63,767
Common stock issued for services	95,001	100,000
Loss on disposal of assets	4,400
Changes in operating assets and liabilities
Restricted cash	-681,126	-237,795
Accounts receivable	5,146,803	1,111,649
Prepaid expenses and other current assets	-437,775	-105,369
Deposits and other assets	-505,838	16,787
Inventory	1,485,748	-2,385,707
Accounts payable, accrued expenses and other liabilities	-6,770,318	2,846,834
Accounts payable, related party	-2,485,172	2,065,319
Net cash provided by operating activities	7,178,179	1,023,818
INVESTING ACTIVITIES
Capital expenditures	-1,720,156	-1,477,729
Proceeds from sale of assets		201,000
Net cash used in investing activities	-1,720,156	-1,276,729
FINANCING ACTIVITIES
Proceeds from issuance of debt		5,750,611
Payments on long-term debt	-6,226,521	-5,274,106
Proceeds from notes payable	2,000,000	15,032
Payments on notes payable	-372,986	-224,805
Net cash provided by (used in) financing activities	-4,599,507	266,732
Net increase in cash and cash equivalents	858,516	13,821
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	434,717	420,896
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,293,233	434,717
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received		800,000
Surety bond funded by seller of pipeline interest	850,000
Non-cash investing and financing activities:
New asset retirement obligations	300,980
Changes in estimates of existing ARO obligations		592,415
Financing of capital expenditures via capital lease	536,635
Accrued services payable converted to common stock		50,000
Interest paid	$1,369,197	$791,536

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Treasury Stock	Total
Beginning Balance, amount at Dec. 31, 2012	$105,633	$36,524,142	($20,008,935)		$16,620,840
Beginning Balance, shares at Dec. 31, 2012	10,563,297
Common stock issued for services, shares	17,676
Common stock issued for services, amount	177	99,823			100,000
Treasury stock acquired, shares				-150,000
Treasury stock acquired, amount				-800,000	-800,000
Net Income (loss)			-3,807,129		-3,807,129
Ending Balance, amount at Dec. 31, 2013	105,810	36,623,965	-23,816,064	-800,000	12,113,711
Ending Balance, shares at Dec. 31, 2013	10,580,973			-150,000
Common stock issued for services, shares	18,471
Common stock issued for services, amount	185	94,816			95,001
Treasury stock acquired, shares
Treasury stock acquired, amount
Net Income (loss)			15,758,756		15,758,756
Ending Balance, amount at Dec. 31, 2014	$105,995	$36,718,781	($8,057,308)	($800,000)	$27,967,468
Ending Balance, shares at Dec. 31, 2014	10,599,444			-150,000

1_Organization

1. Organization	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations

	Blue Dolphin Energy Company (http://www.blue-dolphin-energy.com, referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) is primarily an independent refiner and marketer of petroleum products. Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Wilson County, Texas (the “Nixon Facility”). As part of our refinery business segment, we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties, which are considered non-core to our business. See “Note (4) Business Segment Information” of this report for further discussion of our business segments.

	Structure and Management

	We were formed as a Delaware corporation in 1986. In connection with our reverse acquisition of Lazarus Energy, LLC (“LE”) in 2012, whereby we acquired the Nixon Facility, we:

	(i)	issued 8,426,456 shares of our common stock, par value $0.01 per share (the “Common Stock”) to Lazarus Energy Holdings, LLC (“LEH”) as consideration. As a result, LEH, our controlling shareholder, owns approximately 81% of our Common Stock. Jonathan P. Carroll, Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH; and
	(ii)	entered into a Management Agreement dated and effective February 12, 2012 with LEH. Pursuant to the Management Agreement, LEH manages our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business. On May 12, 2014, the Management Agreement was amended to: (a) extend the term to August 12, 2015, and (b) change the name of the agreement from “Management Agreement” to “Operating Agreement” (the “Operating Agreement”).

	Our operations are conducted directly and indirectly through our primary operating subsidiaries, as follows:

	•	LE, a Delaware limited liability company (petroleum processing assets);
	•	Lazarus Refining & Marketing, LLC, a Delaware limited liability company (petroleum storage and terminaling) (“LRM”);
	•	Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations) (“BDPL”);
	•	Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);
	•	Blue Dolphin Services Co., a Texas corporation (administrative services);
	•	Blue Dolphin Exploration Company, a Delaware corporation (exploration and production investments) (“BDEX”); and
	•	Petroport, Inc., a Delaware corporation (inactive).

2_Basis_of_Presentation

2. Basis of Presentation	12 Months Ended
2. Basis of Presentation	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	We have prepared our audited consolidated financial statements in accordance with United States 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. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading.

3_Significant_Accounting_Polic

3. Significant Accounting Policies	12 Months Ended
3. Significant Accounting Policies	Dec. 31, 2014
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 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

	We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated.

	Cash and Cash Equivalents

	Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $1,293,233 and $434,717 at December 31, 2014 and 2013, respectively.

	Restricted Cash

	On September 29, 2008, LE entered into a certain Loan Agreement (the “Loan Agreement”) with First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10.0 million (the “Refinery Note”). In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”). Restricted cash represents a payment reserve account to be drawn upon by AFNB in the event that we fail to make any payment in a timely manner as required under the Loan Agreement. Restricted cash was $1,008,514 and $327,388 at December 31, 2014 and 2013, respectively.

	Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk

	Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance as necessary for individual customer balances.

	Concentration of Risk

	Bank Accounts

	Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $1,113,977 and $77,388 at December 31, 2014 and 2013, respectively.

	Significant Customers

	Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (16) Concentration of Risk” of this report for additional disclosures related to significant customers.

	Inventory

	The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products. Inventory reflected for crude oil and condensate is nominal and represents line fill. Because refined petroleum products are commodities, we have no control over the changing market value of these inventories. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated impairment expense. See “Note (7) Inventory” of this report for additional disclosures related to our inventory.

	Price-Risk Management Activities

	Under our inventory risk management policy, Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce our commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand-alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, 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. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statement of operations. See “Note (21) Refined Petroleum Products Inventory Risk Management” of this report for additional disclosures related to our inventory risk management policy.

	Property and Equipment

	Refinery and Facilities

	Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included as operating expenses under the Operating Agreement with LEH (see “Note (9) Accounts Payable Related Party” of this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

	Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations.

	For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service.

	Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. 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 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 did not record any impairment of our refinery and facilities for the years ended December 31, 2014 and 2013.

	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 Gulf of Mexico oil and gas properties had no production during the years ended December 31, 2014 and 2013. All leases associated with our Gulf of Mexico oil and gas properties have expired.

	Pipelines and Facilities

	We record pipelines and facilities at the lower of cost or net realizable value. 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, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.

	Construction in Progress

	Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service.

	See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress.

	Intangibles – Other

We recognized trade name in connection with our reverse acquisition of LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014.

Debt Issue Costs

We have debt issue costs related to certain facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations. Debt issue costs, net of accumulated amortization, totaled $479,737 and $498,536 at December 31, 2014 and 2013, respectively. Accumulated amortization was $211,244 and $177,445 at December 31, 2014 and 2013, respectively. Amortization expense, which is included in interest expense, was $33,799 and $33,800 for both years ended December 31, 2014 and 2013. See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

Refined Petroleum Products Revenue

We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil. 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 petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Deferred Revenue

On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”), and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”) whereby BDPL 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 October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL 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 BDPL’s 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 for which the supplemental pipeline bonds secure.

Tank Rental and Easement Revenue

Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in other income. Land easement revenue is recorded monthly and 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.

Income Taxes

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.

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 (18) Income Taxes” of this report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we initiate a review of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. Recoverability of an asset is measured by comparing its carrying amount to the expected future undiscounted cash flows expected to result from the use and eventual disposition of that asset, excluding future interest costs that would be recognized as an expense when incurred. Any impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its fair market value. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.

Asset Retirement Obligations

FASB ASC guidance related to AROs requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. 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 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 plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these 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 (12) Asset Retirement Obligations” of this report for additional information related to our AROs.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. 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. The physical inventory volumes are not exchanged and these contracts are net settled with cash. 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. Therefore, changes in the fair value of these commodity hedging instruments are included as income or expense in the period of change in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined petroleum products sold in our consolidated statements of operations using mark-to-market accounting. See “Note (20) Fair Value Measurement” of this report for additional disclosures related to derivatives.

Computation of Earnings Per Share

We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our audited consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.

The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, 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 (19) Earnings Per Share” for additional information related to EPS.

Stock-Based Compensation

In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period). See “Note (14) Stock Options” for more information related to stock-based compensation.

Treasury Stock

We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (15) Treasury Stock” for additional disclosures related to treasury stock.

Business Combinations

We account for acquisitions in accordance with FASB ASC guidance for business combinations. The guidance requires consideration given, including contingent consideration, assets acquired and liabilities assumed to be valued at their fair market values at the acquisition date. The guidance further provides that: (i) in-process research and development costs be recorded at fair value as an indefinite-lived intangible asset, (ii) acquisition costs generally be expensed as incurred, (iii) restructuring costs associated with a business combination generally be expensed subsequent to the acquisition date; and (iv) changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally affect income tax expense.

The guidance requires that any excess of purchase price over fair value of net assets acquired, including identifiable intangible and liabilities assumed be recognized as goodwill. Any excess of fair value of acquired net assets, including identifiable intangibles assets, over the acquisition consideration results in a bargain purchase gain. Prior to recording a gain, the acquiring entity must reassess whether all acquired assets and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued.

Reclassification

We have reclassified certain insignificant prior year amounts related to our oil and gas exploration and production operations to conform to our 2014 presentation.

New Pronouncements Issued but Not Yet Effective

In May 2014, FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 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. ASU 2014-09 is effective for reporting periods beginning after December 15, 2016, and early adoption is not permitted. We are evaluating the impact that adoption of this guidance will have on the determination or reporting of our financial results.

4_Business_Segment_Information

4. Business Segment Information	12 Months Ended
4. Business Segment Information	Dec. 31, 2014
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. Our “Pipeline Transportation” business segment is considered non-core to our business.

	Segment information for the years ended December 31, 2014 (and at December 31, 2014) was as follows:

			Year Ended December 31, 2014
			Segment
			Refinery			Pipeline			Corporate &
			Operations			Transportation			Other			Total
	Revenue		$	387,304,774		$	220,200		$	-		$	387,524,974
	Less: Operation cost(1)			(374,613,154	)		(483,262	)		(1,242,466	)		(376,338,882	)
	Other non-interest income			1,130,065			270,833			-			1,400,898
	EBITDA		$	13,821,685		$	7,771		$	(1,242,466	)

	Depletion, depreciation and amortization												(1,570,962	)
	Interest expense, net												(844,850	)

	Income before income taxes											$	10,171,178

	Capital expenditures		$	1,720,156		$	-		$	-		$	1,720,156

	Identifiable assets(2)		$	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)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

	Segment information for the year ended December 31, 2013 (and at December 31, 2013) was as follows:

			Year Ended December 31, 2013
			Segment
			Refinery			Pipeline			Corporate &
			Operations			Transportation			Other			Total
	Revenue		$	409,239,747		$	303,322		$	-		$	409,543,069
	Less: Operation cost(1)			(409,800,285	)		(524,051	)		(1,652,160	)		(411,976,496	)
	Other non-interest income			1,113,397			41,667			-			1,155,064
	EBITDA		$	552,859		$	(179,062	)	$	(1,652,160	)

	Depletion, depreciation and amortization												(1,342,563	)
	Interest expense, net												(1,096,948	)

	Loss before income taxes											$	(3,717,874	)

	Capital expenditures		$	1,477,729		$	-		$	-		$	1,477,729

	Identifiable assets(2)		$	54,470,723		$	2,399,467		$	809,311		$	57,679,501

	(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	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

5_Prepaid_Expenses_and_Other_C

5. Prepaid Expenses and Other Current Assets	12 Months Ended
5. Prepaid Expenses and Other Current Assets	Dec. 31, 2014
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,
		2014		2013

	Unrealized hedging gains	$	495,900	$	6,950
	Prepaid insurance		156,558		165,004
	Prepaid professional fees		104,000		104,000
	Prepaid listing fees		15,000		15,000
	Prepaid loan closing fees		-		33,513
	Prepaid taxes		-		9,216

		$	771,458	$	333,683

6_Deposits

6. Deposits	12 Months Ended
6. Deposits	Dec. 31, 2014
Banking and Thrift [Abstract]
Deposits	Deposits consisted of the following:

		December 31,
		2014		2013

	Tax bonds	$	-	$	792,000
	Equipment deposits		48,785		124,526
	Utility deposits		10,250		10,250
	Rent deposits		9,463		9,463
	Purchase option deposits		-		283,421

		$	68,498	$	1,219,660

7_Inventories

7. Inventories	12 Months Ended
7. Inventories	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventories	Inventory consisted of the following:

		December 31,
		2014		2013

	Jet fuel	$	2,631,546	$	1,444,399
	Atmospheric gas oil		224,007		575,919
	Naphtha		194,688		804,490
	Oil-based mud blendstock		124,176		-
	Crude		19,041		19,041
	LPG mix		7,193		28,888
	NRLM		-		1,813,662

		$	3,200,651	$	4,686,399

8_Property_Plant_and_Equipment

8. Property, Plant and Equipment, Net	12 Months Ended
8. Property, Plant and Equipment, Net	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, consisted of the following:

		December 31,
		2014		2013

	Refinery and facilities	$	36,462,451	$	35,852,928
	Pipelines and facilities		2,127,207		1,826,226
	Onshore separation and handling facilities		325,435		325,435
	Land		602,938		577,965
	Other property and equipment		597,064		567,813
			40,115,095		39,150,367

	Less: Accumulated depletion, depreciation and amortization		4,586,575		3,016,713
			35,528,520		36,133,654

	Construction in Progress		1,842,555		255,012

	Property, Plant and Equipment, Net	$	37,371,075	$	36,388,666

9_Accounts_Payable_Related_Par

9. Accounts Payable, Related Party	12 Months Ended
9. Accounts Payable, Related Party	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts Payable, Related Party	LEH, our controlling shareholder, owns approximately 81% of Common Stock. Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. LEH manages all of our subsidiaries and operates all of our assets, including the Nixon Facility, (the “Services”) pursuant to the Operating Agreement.

	With respect to the Nixon Facility, the Operating Agreement covers all refinery operating expenses with the exception of capital expenditures. Pursuant to the Operating Agreement, for management and operation of the Nixon Facility LEH receives as compensation: (i) weekly payments from GEL TEX Marketing, LLC (“GEL”) not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Operating Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Operating Agreement, determined on a monthly basis. For all other assets, LEH is reimbursed at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Operating Agreement is to be paid to LEH within 30 days of the end of each calendar month.

	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 12, 2015, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party.

	Aggregate amounts expensed for Services at the Nixon Facility for the years ended December 31, 2014 and 2013 were $10,698,023 (approximately $2.77 per barrel of throughput) and $10,673,722 (approximately $2.79 per barrel of throughput), respectively.

	At December 31, 2014 and 2013, the amounts outstanding to LEH to fund our working capital requirements were $1,174,168 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.

10_Notes_Payable

10. Notes Payable	12 Months Ended
10. Notes Payable	Dec. 31, 2014
Debt Disclosure [Abstract]
Notes Payable	Notes payable consisted of the following:

		December 31,
		2014		2013

	Short-term note	$	-	$	9,379
	Short-term capital leases		-		2,505

		$	-	$	11,884

	Short-Term Note

	The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing services was $0 and $9,379 at December 31, 2014 and 2013, respectively. The unsecured note was paid off during the first quarter of 2014.

	Short-Term Capital Leases

	The balance on short-term notes under capital lease agreements was $0 and $2,505 at December 31, 2014 and 2013, respectively. These capital leases were paid off during the first quarter of 2014.

11_Accrued_Expenses_and_Other_

11. Accrued Expenses and Other Current Liabilities	12 Months Ended
11. Accrued Expenses and Other Current Liabilities	Dec. 31, 2014
Payables and Accruals [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities consisted of the following:

		December 31,
		2014		2013

	Excise and income taxes payable	$	1,228,411	$	688,754
	Genesis crude accrued payable		521,739		-
	Board of director fees payable		345,000		240,000
	Unearned revenue		252,500		302,505
	Transportation and inspection		190,000		100,000
	Other payable		149,962		269,185
	Insurance		96,092		-

		$	2,783,704	$	1,600,444

12_Asset_Retirement_Obligation

12. Asset Retirement Obligations	12 Months Ended
12. Asset Retirement Obligations	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Refinery and Facilities

	Management has concluded that there is no legal or contractual obligation to dismantle or remove the Nixon Refinery and related facilities. Management believes that the Nixon Refinery and related facilities 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 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.

	Pipelines and Facilities and Oil and Gas Properties

	We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities, as well as the plugging and abandonment of our oil and gas properties. We recorded a discounted liability for the fair value an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset.

	For the years ended December 31, 2014 and 2013, we recognized $0 and $63,767, respectively, in abandonment expense related to our oil and gas properties. Abandonment expense for 2013 related to our High Island A7 and High Island 37 oil and gas properties. Abandonment expense represents amounts incurred in excess of the ARO liability for the related asset. Plugging and abandonment costs for oil and gas properties and pipelines are recorded as information becomes available from operators to substantiate actual and/or probable costs.

	AROs on a roll-forward basis were as follows:

		December 31,
		2014			2013

	Asset retirement obligations, at the beginning of the year	$	1,597,661		$	921,260
	Changes in estimates of existing obligations		-			592,415
	New asset retirement obligations		300,980			-
	Liabilities settled		(243,866	)		(28,700	)
	Accretion expense		211,995			112,686
			1,866,770			1,597,661
	Less: current portion of asset retirement obligations		(85,846	)		(107,388	)

	Long-term asset retirement obligations, at the end of the year	$	1,780,924		$	1,490,273

	For the years ended December 31, 2014 and 2013, we recognized $243,866 and $28,700, respectively, in liabilities settled. For 2014, liabilities settled primarily related to abandonment of pipeline Segment No. 8606. For 2013, liabilities settled related to our High Island 37 oil and gas property. 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 (22) Commitments and Contingencies – Supplemental Pipeline Bonds” of this report.

13_LongTerm_Debt

13. Long-Term Debt	12 Months Ended
13. Long-Term Debt	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consisted of the following:

			December 31,
			2014			2013

	Refinery Note		$	8,648,980		$	9,057,937
	Sovereign Loan			1,638,898			-
	Notre Dame Debt			1,300,000			1,300,000
	Capital Leases			466,401			-
	Construction and Funding Agreement			-			5,747,330
				12,054,279			16,105,267
	Less: current portion of long-term debt			(1,245,476	)		(2,215,918	)
			$	10,808,803		$	13,889,349

	The following is a schedule of future long-term debt payments:

			Future
			Long-Term
	Years Ending December 31,		Debt Payments

	2015		$	1,245,476
	2016			2,616,167
	2017			958,202
	2018			517,543
	2019			546,736
	Subsequent to 2019			6,170,155

			$	12,054,279

	Refinery Note

	The Refinery Note accrues interest at a rate of U.S. Prime Rate plus 2.25% (effective rate of 5.50% at December 31, 2014) and has a maturity date of October 1, 2028 (the “Maturity Date”). LE’s obligations under the Refinery Note are secured by a Deed of Trust (the “Deed of Trust”) of even date with the Loan Agreement. The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Loan Agreement, the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE. The principal balance outstanding on the Refinery Note was $8,648,980 and $9,057,937 at December 31, 2014 and 2013, respectively. Interest was accrued on the Refinery Note in the amount of $47,569 and $40,132 at December 31, 2014 and 2013, respectively.

	The Loan Agreement has debt-to-worth and current ratio financial maintenance covenants (the “Financial Maintenance Covenants”). As of December 31, 2014 and the date of filing this report, we were in compliance with the Financial Maintenance Covenants in the Loan Agreement. As of December 31, 2013, we were in violation of the current ratio covenant in the Loan Agreement. However, AFNB agreed to waive certain financial maintenance covenants relating the Financial Maintenance Covenants under the Loan Agreement in a letter agreement effective December 31, 2013.

	On September 1, 2013, AFNB and LE amended the Refinery Note (the “Note Modification Agreement”). Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310. Other than modification of the payment terms under the Refinery Note, the terms under the Loan Agreement and the Refinery Note remain the same through the Maturity Date and the Refinery Loan Documents remain in full force and effect.

	Sovereign Loan

	On May 2, 2014, LRM entered into a loan and security agreement with Sovereign Bank, a Texas state bank (“Sovereign”), for a term loan facility in the aggregate amount of $2.0 million (the “Sovereign Loan”) at an interest rate of 6.00%. The proceeds of the Sovereign Loan are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. The Sovereign Loan is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio, (ii) secured by the assignment of certain leases of LRM, certain assets of LEH, our controlling shareholder and an affiliated entity, and (iii) guaranteed by Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin and majority owner of LEH and an affiliated entity. The principal balance outstanding on the Sovereign Loan was $1,638,898 and $0 at December 31, 2014 and 2013, respectively. Interest was accrued on the Sovereign Loan in the amount of $8,470 and $0 at December 31, 2014 and 2013, respectively.

	On March 25, 2015, Sovereign and LRM amended the Sovereign Loan pursuant to a Loan Modification Agreement (the “Loan Modification Agreement”). Under the Loan Modification Agreement, the interest rate on the Sovereign Loan was modified to be the greater of the U.S. Prime Rate plus 2.75% or 6.00%. In addition, the maturity date of the Sovereign Loan was extended to March 25, 2017. Pursuant to the Loan Modification Agreement, the monthly payment due under the Sovereign Loan is $61,665 plus interest.

	Notre Dame Debt

	LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8,000,000, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt accrues interest at a rate of 16% and 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. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at December 31, 2014 and 2013. Interest was accrued on the Notre Dame Debt in the amount of $1,274,789 and $1,066,784 at December 31, 2014 and 2013, respectively. There are no financial maintenance covenants associated with the Notre Dame Debt. The due date of the Notre Dame Debt was extended to July 1, 2016.

	Pursuant to Intercreditor and Subordination Agreements dated September 29, 2008 and August 12, 2011, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of the holder of the Refinery Note, the Deed of Trust and Security Agreement and Milam Services, Inc. (“Milam”), an affiliate of Genesis, under the Construction and Funding Agreement, respectively.

	Pursuant to a First Amendment to Promissory Note made effective July 1, 2013, the Notre Dame Debt was amended as follows: (i) the annual interest rate on the unpaid balance was set to 16% and (ii) the final maturity became July 1, 2015.

	Pursuant to a Second Amendment to Promissory Note made effective October 1, 2014, the Notre Dame Debt was amended to extend the maturity date to July 1, 2016.

	Capital Leases

	Long-term capital lease obligations totaled $466,401 and $0 at December 31, 2014 and 2013. The following is a summary of equipment held under long-term capital leases:

			December 31,
			2014			2013

	Cost		$	538,598		$	-
	Less: accumulated depreciation			-			-

			$	538,598		$	-

On August 7, 2014, we entered into a 36 month “build-to-suit” capital lease for the purchase of new boiler equipment for the Nixon Facility. The cost of the equipment has been added to construction in progress until it has been completed, delivered, and placed into service. Depreciation will begin once the equipment has been placed into service. The equipment was delivered in December 2014 and placed in service during the first quarter of 2015. The long-term capital lease obligation requires a quarterly payment in the amount of $42,996.

At December 31, 2014, future minimum lease commitments under non-cancelable capital leases were as follows:

		Future
		Minimum
Years Ending December 31,		Lease Payments

2015		$	171,821
2016			171,821
2017			148,058
2018			-
2019			-
Subsequent to 2019			-

Total future minimum lease payments			491,700
Amount representing interest			(25,299	)
Present value of minimum lease payments		$	466,401

Construction and Funding Agreement

In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations. Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service. All amounts advanced under the Construction and Funding Agreement bore interest at a rate of 6% annually. There were no financial maintenance covenants associated with this obligation.

The principal balance outstanding on the Construction and Funding Agreement was $0 and $5,747,330 at December 31, 2014 and 2013, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $0 and $700,597 at December 31, 2014 and 2013, respectively. As a result of LE’s repayment of all amounts due and owing to Milam pursuant to the Construction and Funding Agreement, LE is now entitled to receive up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement. In addition, Milam is obligated to release all liens on the Nixon Facility. See “Part I, Item 1. Financial Statements - Note (22) Commitments and Contingencies – Genesis Agreements” of this report for additional disclosures related to the Construction and Funding Agreement and our relationship with Genesis.

14_Stock_Options

14. Stock Options	12 Months Ended
14. Stock Options	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Options	Blue Dolphin’s Board established a 2000 Stock Incentive Plan that was subsequently approved by Blue Dolphin’s stockholders on May 18, 2000. As a result of Blue Dolphin’s reverse acquisition of LE, all employees of Blue Dolphin became employees of LEH effective February 15, 2012. Therefore, all options outstanding for Blue Dolphin employees (with the exception of options outstanding for Ivar Siem that expired in October 2013) were cancelled 90 days following the effective date of the reverse merger. At December 31, 2014 and 2013, there were no options outstanding, no options exercisable and no shares of Common Stock reserved for issuance under the 2000 Stock Incentive Plan.

15_Treasury_Stock

15. Treasury Stock	12 Months Ended
15. Treasury Stock	Dec. 31, 2014
Equity [Abstract]
Treasury Stock	In March of 2013, BDEX completed a non-cash transaction to dispose of its 7% undivided working interest in an oil property located in Indonesia (“Indonesia”) pursuant to a Sale and Purchase Agreement with Blue Sky Langsa, Ltd. (“Blue Sky”) dated November 6, 2012. Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of Common Stock, which represented a recovery of a significant portion of the 342,857 shares of Common Stock BDEX paid Blue Sky to acquire Indonesia in 2010. The 150,000 shares of Common Stock acquired from Blue Sky are being held as treasury stock. At December 31, 2014 and 2013, we had 150,000 shares of treasury stock.

16_Concentration_of_Risk

16. Concentration of Risk	12 Months Ended
16. Concentration of Risk	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Concentration of Risk	Key Supplier

	Under the Crude Oil and Supply Throughput Services Agreement by and between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”), GEL is the exclusive supplier of crude oil and condensate to the Nixon Facility. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. The initial term was to expire on August 12, 2014. However, on October 30, 2013, LE entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam (the “October 2013 Letter Agreement”), effective October 24, 2013. In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019, unless sooner terminated by GEL with 180 days prior written notice.

	Significant Customers

	For the year ended December 31, 2014, we had five customers that accounted for approximately 89% of our refined petroleum products sales. These five customers represented approximately $6.4 million in accounts receivable at December 31, 2014. For the year ended December 31, 2013, we had five customers that accounted for approximately 92% of our refined petroleum products sales. These five customers represented approximately $13.4 million in accounts receivable at December 31, 2013.

	Refined Petroleum Product Sales

	All of our refined petroleum products are currently sold in the United States. The following table summarizes total refined petroleum product sales:

		Years Ended December 31,
		2014				2013

	Atmospheric gas oil	$	96,027,339	24.8	%	$	101,955,402	24.9	%
	Naphtha		89,700,423	23.2	%		103,980,651	25.4	%
	Jet fuel		88,479,458	22.8	%		20,048,594	4.9	%
	NRLM		62,729,476	16.2	%		182,513,228	44.6	%
	Oil-based mud blendstock		49,662,414	12.8	%		-	0	%
	LPG mix		705,664	0.2	%		499,277	0.1	%
	Reduced crude		-	0	%		242,595	0.1	%

	Total refined petroleum product sales	$	387,304,774	100	%	$	409,239,747	100	%

	On May 31, 2014, the Nixon Facility ceased production of NRLM, a transportation-related diesel fuel product. On June 1, 2014, the Nixon Facility began producing oil-based mud blendstock, a non-transportation lubricant blend product. The shift in product slate from NRLM to oil-based mud blendstock 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. The Nixon Facility could produce and sell higher ppm sulfur diesel as a feedstock to other refineries and blenders in the United States and as a finished petroleum product to other countries.

	The Nixon Facility began producing jet fuel in late 2013. Jet fuel is produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream. Production of jet fuel, which is considered a higher value product, significantly upgrades the value of the naphtha component.

17_Leases

17. Leases	12 Months Ended
17. Leases	Dec. 31, 2014
Accounting Policies [Abstract]
Leases	Our company headquarters is located in downtown Houston, Harris County, 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, 2014 and 2013, rent expense totaled $98,876 and $113,381, respectively.

	At December 31, 2014, future minimum lease commitments that were non-cancelable under our office lease were as follows:

		Future
		Minimum
	Years Ending December 31,	Lease Payments

	2015	$	116,231
	2016		116,231
	2017		48,429

		$	280,891

18_Income_Taxes

18. Income Taxes	12 Months Ended
18. Income Taxes	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Benefit (Expense)

	Our income tax benefit (expense) consisted of the following:

			Years Ended December 31,
			2014				2013
	Current:
	Federal		$	(64,258	)		$	-
	State			(108,270	)			(89,255	)
	Deferred:
	Federal			5,760,106				-
	State			-				-

			$	5,587,578			$	(89,255	)

	The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin to replace the state’s prior franchise tax structure. 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.

	Our effective tax rate applicable to continuing operations in 2014 and 2013 was as follows:

			2014				2013

	Expected tax rate			34	%			34	%
	Permanent differences			0	%			0	%
	State tax			1.06	%			(2.49	%)
	Federal tax			0.63	%			0	%
	Change in valuation allowance			(90.63	%)			(34.00	%)
				(54.94	%)			(2.49	%)

	Deferred Income Taxes

	Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE in a reverse acquisition in 2012. As a limited liability company, LE’s taxable income or loss flowed through to its sole member for federal and state income tax purposes prior to the reverse acquisition. However, because Blue Dolphin is a “C” corporation, LE’s taxable income or loss now flows through to Blue Dolphin for federal and state income tax purposes.

	Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. Blue Dolphin experienced ownership changes in 2005 in connection with a series of private placements, and in 2012 as a result of the reverse acquisition of LE. The 2012 ownership change will subject NOL carryforwards to an annual use limitation, which will significantly reduce Blue Dolphin’s ability to use them to offset taxable income in periods following the 2012 ownership change. The amount of NOLs subject to such limitations is approximately $18.7 million. As a result of the limitation under IRC Section 382, the annual use limitation is $638,196 per year, the effect of which will result in approximately $6.7 million in NOL carryforwards expiring unused.

	At December 31, 2014, we recognized a net deferred tax asset of approximately $5.7 million, reflecting the future benefit of NOLs generated before and after the 2012 ownership change. NOLs generated subsequent to the 2012 ownership change of approximately $12.1 million are not subject to an annual use limitation under IRC Section 382. We project usage of approximately $1.3 million of NOLs in 2014.

	Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes. The following table shows significant components of our deferred tax assets and liabilities:

			December 31,
			2014				2013
	Deferred tax assets:
	Inventories		$	369			$	-
	Net operating loss and capital loss carryforwards			10,067,144				9,831,410
	Start-up costs (Nixon Facility)			1,648,036				1,785,372
	Asset retirement obligations liability/deferrred revenue			869,821				645,538
	AMT credit			85,098				20,840
	Total deferred tax assets			12,670,468				12,283,160

	Deferred tax liabilities:
	Unrealized hedges			(168,606	)			(2,363	)
	Basis differences in property and equipment			(4,471,434	)			(3,163,568	)
	Total deferred tax liabilities			(4,640,040	)			(3,165,931	)

	Deferred tax assets, net			8,030,428				9,117,229

	Valuation allowance			(2,270,322	)			(9,117,229	)
			$	5,760,106			$	-

	The following table shows our current and noncurrent deferred tax assets (liabilities):

			December 31,
			2014				2013

	Current deferred tax liabilities, net		$	(168,237	)		$	(2,363	)
Noncurrent deferred tax assets, net			8,198,665				9,119,592
Deferred tax assets, net			8,030,428				9,117,229

Valuation allowance			(2,270,322	)			(9,117,229	)
		$	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, 2014, management determined that sufficient positive evidence exists to conclude that it is more likely than not that net deferred tax assets of approximately $5.7 million are realizable, and as a result, reduced the valuation allowance accordingly.

Uncertain Tax Positions

We have adopted the provisions of the ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. 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. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The provisions of the guidance on accounting for uncertainty in income taxes have been applied to all of our material tax positions taken for all open tax years on the date of adoption through the year ended December 31, 2014. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the guidance.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2014 and 2013. 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, 2014, fiscal years 2009 and later remain subject to examination by the IRS and fiscal years 2008 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.

19_Earnings_Per_Share

19. Earnings Per Share	12 Months Ended
19. Earnings Per Share	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share	The following table provides reconciliation between basic and diluted income (loss) per share:

		Years Ended December 31,
		2014		2013

	Net income (loss)	$	15,758,756	$	(3,807,129	)

	Basic and diluted income (loss) per share	$	1.51	$	(0.36	)

	Basic and Diluted
	Weighted average number of shares of common stock
	outstanding and potential dilutive shares of common stock		10,441,464		10,445,883

	Diluted EPS is computed by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the year ended December 31, 2014 and 2013 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

20_Fair_Value_Measurement

20. Fair Value Measurement

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurement

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.

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, 2014 and 2013 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at December 31, 2014 and 2013 was $12,054,279 and $16,117,151, 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, 2014 and the basis for that measurement:

Fair Value Measurement at December 31, 2014 Using

Financial assets (liabilities):

Carrying Value at

Quoted Prices in Active

Significant Unobservable

31-Dec-14

Markets for Identical Assets

Inputs (Level 2)

Inputs (Level 3)

or Liabilities (Level 1)

Commodity contracts

495,900

Fair Value Measurement at December 31, 2013 Using

Financial assets (liabilities):

Carrying Value at

Quoted Prices in Active

Significant Unobservable

31-Dec-14

Markets for Identical Assets

Inputs (Level 2)

Inputs (Level 3)

or Liabilities (Level 1)

Commodity contracts

6,950

Carrying amounts of commodity contracts executed by Genesis are reflected as other current assets or other current liabilities in our consolidated balance sheets.

21_Refined_Petroleum_Products_

21. Refined Petroleum Products Inventory Risk Management

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products 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 petroleum products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end.

Commodity transactions are executed by Genesis to minimize transaction costs, monitor consolidated net exposures and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a 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, 2014, 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

115,000

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at December 31, 2014 and 2013:

Fair Value

December 31,

Asset Derivatives

Balance Sheets Location

2014

2013

Prepaid expenses and other current

assets (accrued expenses and other

Commodity contracts

current liabilities)

495,900

6,950

The following table provides the effect of derivative instruments in our consolidated statements of operations for the years ended December 31, 2014 and 2013:

Gain (Loss) Recognized

Years Ended December 31,

Derivatives

Statements of Operations Location

2014

2013

Commodity contracts

Cost of refined products sold

3,816,871

-103,160

22_Commitments_and_Contingenci

22. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Operating Agreement
	See “Note (9) Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement.

	Genesis Agreements

	We continue to be dependent on our relationship with Genesis and its affiliates. Our relationship with Genesis is governed by three agreements:

	●	Crude Supply Agreement – Pursuant to the Crude Supply Agreement, GEL, an affiliate of Genesis, is the exclusive supplier of crude oil and condensate to the Nixon Facility. 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 LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three 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 on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019, unless sooner terminated by GEL with 180 days prior written notice.

	●	Construction and Funding Agreement – Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam made advances in excess of their obligation for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits (as defined below) of LE in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil and condensate) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.

		So long as the Construction and Funding Agreement remains in effect, LE is prohibited from: (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.

		In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility. All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.

	●	Joint Marketing Agreement – The Joint Marketing Agreement sets forth the terms of an agreement between LE and GEL pursuant to which the parties will jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is 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. However, all payments for the sale of output produced at the Nixon Facility will be 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 follows:

	(a)	First, prior to the date on which Milam has recouped all amounts advanced to LE under the Construction and Funding Agreement (the “Investment Threshold Date”), the Base Construction Payment of $150,000 shall be paid to GEL (for remittance to Milam) each calendar month to satisfy amounts owed under the Construction and Funding Agreement, with a catch-up in subsequent months if there is a Deficit Amount until such Deficit Amount has been satisfied in full.

	(b)	Second, prior to and as of the Investment Threshold Date, LE is 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 Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.

	(c)	Third, prior to the Investment Threshold Date and subject to the payment of the Base Construction Payment by LE and the Operations Payments by GEL, pursuant to (a) and (b) above, an amount shall be paid to GEL from Gross Profits equal to transportation costs, tank storage fees (if applicable), financial statement preparation fees (collectively, the “GEL Expense Items”), after which GEL shall be paid 80% of the remaining Gross Profits (any percentage of Gross Profits distributed to GEL, the “GEL Profit Share”) and LE shall be paid 20% of the remaining Gross Profits (any percentage of Gross Profits distributed to LE, the “LE Profit Share”); provided, however, that in the event that there is a forbearance payment of Gross Profits required by LE under a forbearance agreement with a bank, then 50% of the LE Profit Share shall be directly remitted by GEL to the bank on LE’s behalf until such forbearance amount is paid in full; and provided further that, if there is a Deficit Amount due under the Construction and Funding Agreement and a forbearance payment of Gross Profits that would otherwise be due and payable to the bank for such period, then GEL shall receive 80% of the Gross Profit and 10% shall be payable to the bank and LE shall not receive any of the LE Profit Share until such time as the Deficit Amount is reduced to zero.

	(d)	Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE 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) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.

	(e)	After the Investment Threshold Date, if GEL sustains losses, it can recoup those losses 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.

	The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is 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 on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019, unless sooner terminated by GEL with 180 days prior written notice.

	●	Amendments and Clarifications to the Joint Marketing Agreement – The Joint Marketing Agreement was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

	(a)	In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our obligations amount under the Construction and Funding Agreement. In addition, the parties agreed to amend the priority of payments to reflect that, to the extent that there are available funds in a particular month, AFNB shall be paid one-tenth of such funds, provided that we will not participate in available funds until Deficit Amounts added to the Construction and Funding Agreement are paid in full.

	(b)	In December 2012, GEL made Operations Payments and other payments to or on behalf of LE in which the aggregate amount exceeded the amount payable to LE in the month of December 2012 under the Joint Marketing Agreement (the “Overpayment Amount”). In December 2012, we entered into an amendment to the Joint Marketing Agreement whereby GEL and Milam agreed that Gross Profits payable to LE would be redirected to GEL as payment for the Overpayment Amount until such Overpayment Amount has been satisfied in full. Such redistributions shall not reduce the distributions of Gross Profit that GEL or Milam are otherwise entitled to under the Joint Marketing Agreement.

	(c)	In February 2013, Milam paid a vendor $64,358 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees. In addition, Milam and GEL incurred legal fees and expenses related to settling the matter. In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

	(d)	In February 2013, GEL agreed to advance to LE the funds necessary to pay for the actual costs incurred for the scheduled maintenance turnaround at the Nixon Facility and capital expenditures relating to an electronic product meter, lab equipment and certain piping in an amount equal to the actual costs of the refinery turnaround and capital expenditures, not to exceed $840,000 in the aggregate. In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed that all amounts advanced by GEL or its affiliates to LE pursuant to the letter agreement shall constitute obligations under the Construction and Funding Agreement.

	The principal balance outstanding on the Construction and Funding Agreement was $0 and $5,747,330 at December 31, 2014 and December 31, 2013, respectively. As a result of LE’s repayment of all amounts due and owing to Milam pursuant to the Construction and Funding Agreement, LE receives up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement and Milam is obligated to release all liens on the Nixon Facility.

	Master Easement Agreement - BDPL and FLNG Land

	On October 30, 2014, FLNG Land, II, Inc., a Delaware corporation (“FLNG”) exercised its option to make a second payment of $250,000 to BDPL pursuant to a Master Easement Agreement (the “Master Easement Agreement”) dated December 11, 2013 (the “Effective Date”). Under the Master Easement Agreement, BDPL is providing FLNG with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG (the “Access Easement”) and (ii) a pipeline easement and right of way across certain property of BDPL to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”). FLNG paid BDPL $250,000 on the Effective Date as initial consideration for the grant of the Easements.

	FLNG’s second payment of $250,000 will result in FLNG making annual payments in the amount of $500,000 to BDPL in October of each year for a minimum of five (5) years. One year after the final annual payment of $500,000 is made to BDPL, FLNG will begin paying to BDPL annual payments of $10,000 for so long as FLNG desires to use the Access Easement.

	Supplemental Pipeline Bonds

	We are required to satisfy supplemental pipeline bonding requirements of the Bureau of Ocean Energy Management (“BOEM”) with regard to certain pipelines that we operate in federal waters of the Gulf of Mexico. These supplemental pipeline bonding requirements are intended to secure our performance of plugging and abandonment obligations with respect to these pipelines. Once plugging and abandonment work has been completed, the collateral backing the supplemental pipeline bonds will be released to us.

	In August 2006, BDPL secured a $700,000 supplemental pipeline bond for Right-of-Way Number OCS-G 01381. On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. The $850,000 in cash was used to: (i) increase the supplemental pipeline bond for Right-of-Way Number OCS-G 01381 by $205,000, increasing the total cash-backed collateral for this right-of-way to $905,000, and (ii) secure a $645,000 cash-backed supplemental pipeline bond for Right-of-Way Number OCS-G 08606.

	In December 2014, BDPL completed plugging and abandonment work for Right-of-Way Number OCS-G 08606. As a result, BDPL anticipates release of the collateral backing this supplemental pipeline bond by BOEM in the first half of 2015. There can be no assurance that BOEM will not require additional supplemental pipeline bonds related to other BDPL pipeline right-of-ways.

	Legal Matters

	From time to time we are subject to various lawsuits, claims, mechanics liens and administrative proceedings that arise out of the normal course of business. Management does not believe that the liens, if any, will have a material adverse effect on our results of operations.

	Health, Safety and Environmental Matters

	All of our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of jet fuel and other products; and the monitoring, reporting and control of greenhouse gas emissions. Our operations also require numerous permits and authorizations under various environmental, health and safety laws and regulations. Failure to obtain and comply with these permits or environmental, health or safety laws generally could result in fines, penalties or other sanctions, or a revocation of our permits.

23_Subsequent_Events

23. Subsequent Events	12 Months Ended
23. Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	On March 25, 2015, Sovereign and LRM amended the Sovereign Loan pursuant to a Loan Modification Agreement. Under the Loan Modification Agreement, the interest rate on the Sovereign Loan was modified to be the greater of the U.S. Prime Rate plus 2.75% or 6.00%. In addition, the maturity date of the Sovereign Loan was extended to March 25, 2017. Pursuant to the Loan Modification Agreement, the monthly payment due under the Sovereign Loan is $61,665 plus interest.

	See “Part II, Item 8. Financial Statements and Supplementary Data – Note (13) Long-Term Debt” of this report for additional information related to the Sovereign Loan.

3_Significant_Accounting_Polic1

3. Significant Accounting Policies (Policies)	12 Months Ended
3. Significant Accounting Policies (Policies)	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of presentation	We have prepared our audited consolidated financial statements in accordance with United States 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. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading.
Use of Estimates	We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated.
Cash and Cash Equivalents	Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $1,293,233 and $434,717 at December 31, 2014 and 2013, respectively.
Restricted Cash	On September 29, 2008, LE entered into a certain Loan Agreement (the “Loan Agreement”) with First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10.0 million (the “Refinery Note”). In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”). Restricted cash represents a payment reserve account to be drawn upon by AFNB in the event that we fail to make any payment in a timely manner as required under the Loan Agreement. Restricted cash was $1,008,514 and $327,388 at December 31, 2014 and 2013, respectively.
Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk	Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance as necessary for individual customer balances.
Concentration of Risk	Bank Accounts

	Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $1,113,977 and $77,388 at December 31, 2014 and 2013, respectively.

	Significant Customers

	Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (16) Concentration of Risk” of this report for additional disclosures related to significant customers.
Inventory	The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products. Inventory reflected for crude oil and condensate is nominal and represents line fill. Because refined petroleum products are commodities, we have no control over the changing market value of these inventories. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated impairment expense. See “Note (7) Inventory” of this report for additional disclosures related to our inventory.
Price-Risk Management Activities	Under our inventory risk management policy, Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce our commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand-alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, 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. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statement of operations. See “Note (21) Refined Petroleum Products Inventory Risk Management” of this report for additional disclosures related to our inventory risk management policy.
Property and Equipment	Refinery and Facilities

	Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included as operating expenses under the Operating Agreement with LEH (see “Note (9) Accounts Payable Related Party” of this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

	Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations.

	For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service.

	Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. 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 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 did not record any impairment of our refinery and facilities for the years ended December 31, 2014 and 2013.

	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 Gulf of Mexico oil and gas properties had no production during the years ended December 31, 2014 and 2013. All leases associated with our Gulf of Mexico oil and gas properties have expired.

	Pipelines and Facilities

	We record pipelines and facilities at the lower of cost or net realizable value. 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, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.

	Construction in Progress

	Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service.

	See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress.
Intangibles - Other	We recognized trade name in connection with our reverse acquisition of LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014.
Debt Issue Costs	We have debt issue costs related to certain facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations. Debt issue costs, net of accumulated amortization, totaled $479,737 and $498,536 at December 31, 2014 and 2013, respectively. Accumulated amortization was $211,244 and $177,445 at December 31, 2014 and 2013, respectively. Amortization expense, which is included in interest expense, was $33,799 and $33,800 for both years ended December 31, 2014 and 2013. See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.
Revenue Recognition	Refined Petroleum Products Revenue

	We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil. 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 petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

	Deferred Revenue

	On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”), and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”) whereby BDPL 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 October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL 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 BDPL’s 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 for which the supplemental pipeline bonds secure.

	Tank Rental and Easement Revenue

	Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in other income. Land easement revenue is recorded monthly and 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.
Income Taxes	We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.

	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 (18) Income Taxes” of this report for further information related to income taxes.
Impairment or Disposal of Long-Lived Assets	In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we initiate a review of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. Recoverability of an asset is measured by comparing its carrying amount to the expected future undiscounted cash flows expected to result from the use and eventual disposition of that asset, excluding future interest costs that would be recognized as an expense when incurred. Any impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its fair market value. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.
Asset Retirement Obligations	FASB ASC guidance related to AROs requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

	Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. 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 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 plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these 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 (12) Asset Retirement Obligations” of this report for additional information related to our AROs.
Derivatives	We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. 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. The physical inventory volumes are not exchanged and these contracts are net settled with cash. 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. Therefore, changes in the fair value of these commodity hedging instruments are included as income or expense in the period of change in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined petroleum products sold in our consolidated statements of operations using mark-to-market accounting. See “Note (20) Fair Value Measurement” of this report for additional disclosures related to derivatives.
Computation of Earnings Per Share	We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our audited consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.

	The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, 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 (19) Earnings Per Share” for additional information related to EPS.
Stock Based Compensation	In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period). See “Note (14) Stock Options” for more information related to stock-based compensation.
Treasury Stock	We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (15) Treasury Stock” for additional disclosures related to treasury stock.
Business Combinations	We account for acquisitions in accordance with FASB ASC guidance for business combinations. The guidance requires consideration given, including contingent consideration, assets acquired and liabilities assumed to be valued at their fair market values at the acquisition date. The guidance further provides that: (i) in-process research and development costs be recorded at fair value as an indefinite-lived intangible asset, (ii) acquisition costs generally be expensed as incurred, (iii) restructuring costs associated with a business combination generally be expensed subsequent to the acquisition date; and (iv) changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally affect income tax expense.

	The guidance requires that any excess of purchase price over fair value of net assets acquired, including identifiable intangible and liabilities assumed be recognized as goodwill. Any excess of fair value of acquired net assets, including identifiable intangibles assets, over the acquisition consideration results in a bargain purchase gain. Prior to recording a gain, the acquiring entity must reassess whether all acquired assets and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued.
Reclassification	We have reclassified certain insignificant prior year amounts related to our oil and gas exploration and production operations to conform to our 2014 presentation.
New Pronouncements Issued but Not Yet Effective	In May 2014, FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 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. ASU 2014-09 is effective for reporting periods beginning after December 15, 2016, and early adoption is not permitted. We are evaluating the impact that adoption of this guidance will have on the determination or reporting of our financial results.

4_Business_Segment_Information1

4. Business Segment Information (Tables)	12 Months Ended
4. Business Segment Information (Tables)	Dec. 31, 2014
Segment Reporting [Abstract]
Business segment reporting	Segment information for the years ended December 31, 2014 (and at December 31, 2014) was as follows:

		Year Ended December 31, 2014
		Segment
		Refinery			Pipeline			Corporate &
		Operations			Transportation			Other			Total
	Revenue	$	387,304,774		$	220,200		$	-		$	387,524,974
	Less: Operation cost(1)		(374,613,154	)		(483,262	)		(1,242,466	)		(376,338,882	)
	Other non-interest income		1,130,065			270,833			-			1,400,898
	EBITDA	$	13,821,685		$	7,771		$	(1,242,466	)

	Depletion, depreciation and amortization											(1,570,962	)
	Interest expense, net											(844,850	)

	Income before income taxes										$	10,171,178

	Capital expenditures	$	1,720,156		$	-		$	-		$	1,720,156

	Identifiable assets(2)	$	50,950,050		$	3,028,719		$	6,428,388		$	60,407,157

	Segment information for the year ended December 31, 2013 (and at December 31, 2013) was as follows:

		Year Ended December 31, 2013
		Segment
		Refinery			Pipeline			Corporate &
		Operations			Transportation			Other			Total
	Revenue	$	409,239,747		$	303,322		$	-		$	409,543,069
	Less: Operation cost(1)		(409,800,285	)		(524,051	)		(1,652,160	)		(411,976,496	)
	Other non-interest income		1,113,397			41,667			-			1,155,064
	EBITDA	$	552,859		$	(179,062	)	$	(1,652,160	)

	Depletion, depreciation and amortization											(1,342,563	)
	Interest expense, net											(1,096,948	)

	Loss before income taxes										$	(3,717,874	)

	Capital expenditures	$	1,477,729		$	-		$	-		$	1,477,729

	Identifiable assets(2)	$	54,470,723		$	2,399,467		$	809,311		$	57,679,501

5_Prepaid_Expenses_and_Other_C1

5. Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
5. Prepaid Expenses and Other Current Assets (Tables)	Dec. 31, 2014
Prepaid Expenses And Other Current Assets Tables
Prepaid balances	Prepaid expenses and other current assets consisted of the following:

		December 31,
		2014		2013

	Unrealized hedging gains	$	495,900	$	6,950
	Prepaid insurance		156,558		165,004
	Prepaid professional fees		104,000		104,000
	Prepaid listing fees		15,000		15,000
	Prepaid loan closing fees		-		33,513
	Prepaid taxes		-		9,216

		$	771,458	$	333,683

6_Deposits_Tables

6. Deposits (Tables)	12 Months Ended
6. Deposits (Tables)	Dec. 31, 2014
Deposits Tables
Deposit balances	Deposits consisted of the following:

		December 31,
		2014		2013

	Tax bonds	$	-	$	792,000
	Equipment deposits		48,785		124,526
	Utility deposits		10,250		10,250
	Rent deposits		9,463		9,463
	Purchase option deposits		-		283,421

		$	68,498	$	1,219,660

7_Inventories_Tables

7. Inventories (Tables)	12 Months Ended
7. Inventories (Tables)	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventories balances	Inventory consisted of the following:

		December 31,
		2014		2013

	Jet fuel	$	2,631,546	$	1,444,399
	Atmospheric gas oil		224,007		575,919
	Naphtha		194,688		804,490
	Oil-based mud blendstock		124,176		-
	Crude		19,041		19,041
	LPG mix		7,193		28,888
	NRLM		-		1,813,662

		$	3,200,651	$	4,686,399

8_Property_Plant_and_Equipment1

8. Property, Plant and Equipment, Net (Tables)	12 Months Ended
8. Property, Plant and Equipment, Net (Tables)	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property and equipment	Property, plant and equipment, net, consisted of the following:

		December 31,
		2014		2013

	Refinery and facilities	$	36,462,451	$	35,852,928
	Pipelines and facilities		2,127,207		1,826,226
	Onshore separation and handling facilities		325,435		325,435
	Land		602,938		577,965
	Other property and equipment		597,064		567,813
			40,115,095		39,150,367

	Less: Accumulated depletion, depreciation and amortization		4,586,575		3,016,713
			35,528,520		36,133,654

	Construction in Progress		1,842,555		255,012

	Property, Plant and Equipment, Net	$	37,371,075	$	36,388,666

10_Notes_Payable_Tables

10. Notes Payable (Tables)	12 Months Ended
10. Notes Payable (Tables)	Dec. 31, 2014
Debt Disclosure [Abstract]
Notes Payable	Notes payable consisted of the following:

		December 31,
		2014		2013

	Short-term notes	$	-	$	9,379
	Short-term capital leases		-		2,505

		$	-	$	11,884

11_Accrued_Expenses_and_Other_1

11. Accrued Expenses and Other Current Liabilities (Tables)	12 Months Ended
11. Accrued Expenses and Other Current Liabilities (Tables)	Dec. 31, 2014
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,
		2014		2013

	Excise and income taxes payable	$	1,228,411	$	688,754
	Genesis crude accrued payable		521,739		-
	Board of director fees payable		345,000		240,000
	Unearned revenue		252,500		302,505
	Transportation and inspection		190,000		100,000
	Other payable		149,962		269,185
	Insurance		96,092		-

		$	2,783,704	$	1,600,444

12_Asset_Retirement_Obligation1

12. Asset Retirement Obligations (Tables)	12 Months Ended
12. Asset Retirement Obligations (Tables)	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	AROs on a roll-forward basis were as follows:

		December 31,
		2014			2013

	Asset retirement obligations, at the beginning of the year	$	1,597,661		$	921,260
	Changes in estimates of existing obligations		-			592,415
	New asset retirement obligations		300,980			-
	Liabilities settled		(243,866	)		(28,700	)
	Accretion expense		211,995			112,686
			1,866,770			1,597,661
	Less: current portion of asset retirement obligations		(85,846	)		(107,388	)

	Long-term asset retirement obligations, at the end of the year	$	1,780,924		$	1,490,273

13_LongTerm_Debt_Tables

13. Long-Term Debt (Tables)	12 Months Ended
13. Long-Term Debt (Tables)	Dec. 31, 2013
Debt Disclosure [Abstract]
Long Term Debt	Long-term debt consisted of the following:

		December 31,
		2014			2013

	Refinery Note	$	8,648,980		$	9,057,937
	Sovereign Loan		1,638,898			-
	Notre Dame Debt		1,300,000			1,300,000
	Capital Leases		466,401			-
	Construction and Funding Agreement		-			5,747,330
			12,054,279			16,105,267
	Less: current portion of long-term debt		-1,245,476			(2,215,918	)
		$	10,808,803		$	13,889,349
Schedule of future long-term debt payments	The following is a schedule of future long-term debt payments:

		Future
		Long-Term
	Years Ending December 31,	Debt Payments

	2015	$	1,245,476
	2016		2,616,167
	2017		958,202
	2018		517,543
	2019		546,736
	Subsequent to 2019		6,170,155

		$	12,054,279
Schedule of long-term capital leases	Long-term capital lease obligations totaled $466,401 and $0 at December 31, 2014 and 2013. The following is a summary of equipment held under long-term capital leases:

		December 31,
		2014			2013

	Cost	$	538,598		$	-
	Less: accumulated depreciation		-			-

		$	538,598		$	-
Future minimum lease commitments under non-cancelable capital leases
		Future
		Minimum
	Years Ending December 31,	Lease Payments

	2015	$	171,821
	2016		171,821
	2017		148,058
	2018		-
	2019		-
	Subsequent to 2019		-

	Total future minimum lease payments		491,700
	Amount representing interest		(25,299	)
	Present value of minimum lease payments	$	466,401

16_Concentration_of_Risk_Table

16. Concentration of Risk (Tables)	12 Months Ended
16. Concentration of Risk (Tables)	Dec. 31, 2014
Concentration Of Risk Tables
Percentages of all refined petroleum products sales to total sales	All of our refined petroleum products are currently sold in the United States. The following table summarizes total refined petroleum product sales:

		Years Ended December 31,
		2014				2013

	Atmospheric gas oil	$	96,027,339	24.8	%	$	101,955,402	24.9	%
	Naphtha		89,700,423	23.2	%		103,980,651	25.4	%
	Jet fuel		88,479,458	22.8	%		20,048,594	4.9	%
	NRLM		62,729,476	16.2	%		182,513,228	44.6	%
	Oil-based mud blendstock		49,662,414	12.8	%		-	0	%
	LPG mix		705,664	0.2	%		499,277	0.1	%
	Reduced crude		-	0	%		242,595	0.1	%

	Total refined petroleum product sales	$	387,304,774	100	%	$	409,239,747	100	%

17_Leases_Tables

17. Leases (Tables)	12 Months Ended
17. Leases (Tables)	Dec. 31, 2014
Accounting Policies [Abstract]
Future minimum lease payments	At December 31, 2014, future minimum lease commitments that were non-cancelable under our office lease were as follows:

		Future
		Minimum
	Years Ending December 31,	Lease Payments

	2015	$	116,231
	2016		116,231
	2017		48,429

		$	280,891

18_Income_Taxes_Tables

18. Income Taxes (Tables)	12 Months Ended
18. Income Taxes (Tables)	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Our income tax benefit (expense) consisted of the following:

		Years Ended December 31,
		2014			2013
	Current:
	Federal	$	(64,258	)	$	-
	State		(108,270	)		(89,255	)
	Deferred:
	Federal		5,760,106			-
	State		-			-

		$	5,587,578		$	(89,255	)
Effective tax rate	Our effective tax rate applicable to continuing operations in 2014 and 2013 was as follows:

		2014			2013

	Expected tax rate		34	%		34	%
	Permanent differences		0	%		0	%
	State tax		1.06	%		(2.49	%)
	Federal tax		0.63	%		0	%
	Change in valuation allowance		(90.63	%)		(34.00	%)
			(54.94	%)		(2.49	%)
Deferred tax assets and deferred tax liabilities	Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes. The following table shows significant components of our deferred tax assets and liabilities:

		December 31,
		2014			2013
	Deferred tax assets:
	Inventories	$	369		$	-
	Net operating loss and capital loss carryforwards		10,067,144			9,831,410
	Start-up costs (Nixon Facility)		1,648,036			1,785,372
	Asset retirement obligations liability/deferrred revenue		869,821			645,538
	AMT credit		85,098			20,840
	Total deferred tax assets		12,670,468			12,283,160

	Deferred tax liabilities:
	Unrealized hedges		(168,606	)		(2,363	)
	Basis differences in property and equipment		(4,471,434	)		(3,163,568	)
	Total deferred tax liabilities		(4,640,040	)		(3,165,931	)

	Deferred tax assets, net		8,030,428			9,117,229

	Valuation allowance		(2,270,322	)		(9,117,229	)
		$	5,760,106		$	-
Current and noncurrent deferred tax assets (liabilities)	The following table shows our current and noncurrent deferred tax assets (liabilities):

		December 31,
		2014			2013

	Current deferred tax liabilities, net	$	(168,237	)	$	(2,363	)
	Noncurrent deferred tax assets, net		8,198,665			9,119,592
	Deferred tax assets, net		8,030,428			9,117,229

	Valuation allowance		(2,270,322	)		(9,117,229	)
		$	5,760,106		$	-

19_Earnings_Per_Share_Tables

19. Earnings Per Share (Tables)	12 Months Ended
19. Earnings Per Share (Tables)	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings per share	The following table provides reconciliation between basic and diluted income (loss) per share:

		Years Ended December 31,
		2014		2013

	Net income (loss)	$	15,758,756	$	(3,807,129	)

	Basic and diluted income (loss) per share	$	1.51	$	(0.36	)

	Basic and Diluted
	Weighted average number of shares of common stock
	outstanding and potential dilutive shares of common stock		10,441,464		10,445,883

20_Fair_Value_Measurement_Tabl

20. Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014 and the basis for that measurement:

Fair Value Measurement at December 31, 2014 Using

Financial assets (liabilities):

Carrying Value at

Quoted Prices in Active

Significant Unobservable

31-Dec-14

Markets for Identical Assets

Inputs (Level 2)

Inputs (Level 3)

or Liabilities (Level 1)

Commodity contracts

495,900

Fair Value Measurement at December 31, 2013 Using

Financial assets (liabilities):

Carrying Value at

Quoted Prices in Active

Significant Unobservable

31-Dec-14

Markets for Identical Assets

Inputs (Level 2)

Inputs (Level 3)

or Liabilities (Level 1)

Commodity contracts

6,950

21_Refined_Products_Inventory_

21. Refined Products Inventory Risk Management (Tables)

12 Months Ended

Dec. 31, 2014

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

115,000

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, 2014 and 2013:

Fair Value

December 31,

Asset Derivatives

Balance Sheets Location

2014

2013

Prepaid expenses and other current

assets (accrued expenses and other

Commodity contracts

current liabilities)

495,900

6,950

Effect of derivative instruments

The following table provides the effect of derivative instruments in our consolidated statements of operations for the years ended December 31, 2014 and 2013:

Gain (Loss) Recognized

Years Ended December 31,

Derivatives

Statements of Operations Location

2014

2013

Commodity contracts

Cost of refined products sold

3,816,871

-103,160

3_Significant_Accounting_Polic2

3. Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Cash and cash equivalents	$1,293,233	$434,717	$420,896
Restricted cash	1,008,514	327,388
FDIC limit per depositer	250,000
Cash balances in excess of FDIC insurance limit per depositor	1,113,977	77,388
Accumulated amortization	211,244	177,445
Amortization expense	33,799	33,800
Debt issuance costs	$479,737	$498,536

4_Business_Segment_Information2

4. Business Segment Information (Details) (USD $)	12 Months Ended
4. Business Segment Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Revenues	$387,524,974	$409,543,069
Operation cost (1)	-376,338,882	-411,976,496
Other non-interest income	1,400,898	1,155,064
Depletion, depreciation and amortization	-1,570,962	-1,342,563
Other expense, net	-844,850	-1,096,948
Income (Loss) before income taxes	10,171,178	-3,717,874
Capital expenditures	1,720,156	1,477,729
Identifiable assets	60,407,157	57,679,501
Segment Refinery Operations [Member]
Revenues	387,304,774	409,239,747
Operation cost (1)	-374,613,154	-409,800,285
Other non-interest income	1,130,065	1,113,397
EBITDA	13,821,685	552,859
Capital expenditures	1,720,156	1,477,729
Identifiable assets	50,950,050	54,470,723
Segment Pipeline Transportation [Member]
Revenues	220,200	303,322
Operation cost (1)	-483,262	-524,051
Other non-interest income	270,833	41,667
EBITDA	7,771	-179,062
Capital expenditures
Identifiable assets	3,028,719	2,399,467
Corporate and Other
Revenues
Operation cost (1)	-1,242,466	-1,652,160
Other non-interest income
EBITDA	-1,242,466	-1,652,160
Capital expenditures
Identifiable assets	$6,428,388	$809,311

5_Prepaid_Expenses_and_Other_C2

5. Prepaid Expenses and Other Current Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Prepaid Expenses And Other Current Assets Details
Unrealized hedging gains	$495,900	$6,950
Prepaid insurance	156,558	165,004
Prepaid professional fees	104,000	104,000
Prepaid listing fees	15,000	15,000
Prepaid loan closing fees		33,513
Prepaid taxes		9,216
Employee advances	$771,458	$333,683

6_Deposits_Details

6. Deposits (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Deposits Details
Tax bonds		$792,000
Equipment deposits	48,785	124,526
Utility deposits	10,250	10,250
Rent deposits	9,463	9,463
Purchase option deposits		283,421
Deposits	$68,498	$1,219,660

7_Inventories_Details

7. Inventories (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Jet fuel	$2,631,546	$1,444,399
Atmospheric gas oil	224,007	575,919
Naphtha	194,688	804,490
Oil-based mud blendstock	124,176
Crude	19,041	19,041
LPG mix	7,193	28,888
NRLM		1,813,662
Inventories, Net	$3,200,651	$4,686,399

8_Property_Plant_and_Equipment2

8. Property, Plant and Equipment, Net (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment Net Details
Refinery and facilities	$36,462,451	$35,852,928
Pipelines and facilities	2,127,207	1,826,226
Onshore separation and handling facilities	325,435	325,435
Land	602,938	577,965
Other property and equipment	597,064	567,813
Property, Plant and Equipment, Gross	40,115,095	39,150,367
Less: Accumulated depletion, depreciation and amortization	4,586,575	3,016,713
Property, Plant and Equipment less depreciation	35,528,520	36,133,654
Construction in Progress	1,842,555	255,012
Property, Plant and Equipment, Net	$37,371,075	$36,388,666

9_Accounts_Payable_Related_Par1

9. Accounts Payable, Related Party (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Payables and Accruals [Abstract]
Expense for service	$10,698,023	$10,673,722
Accounts payable, related party	$1,174,168	$3,659,340

10_Note_Payable_Details

10. Note Payable (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Short-term notes		$9,379
Short-Term Captial Leases		2,505
Note Payable,Total		$11,884

10_Note_Payable_Details_Narrat

10. Note Payable (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Financing services cost	$0	$9,379
Unsecured short-term notes	$0	$2,505

11_Accrued_Expenses_and_Other_2

11. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Accrued Expenses And Other Current Liabilities Details
Excise and income taxes payable	$1,228,411	$688,754
Genesis crude accrued payable	521,739
Board of director fees payable	345,000	240,000
Unearned revenue	252,500	302,505
Transportation and inspection	190,000	100,000
Other payable	149,962	269,185
Insurance	96,092
Accrued Expenses and Other Current Liabilities, Net	$2,783,704	$1,600,444

12_Asset_Retirement_Obligation2

12. Asset Retirement Obligations (Details) (USD $)	12 Months Ended
12. Asset Retirement Obligations (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations Details
Asset retirement obligations, at the beginning of the year	$1,597,661	$921,260
Changes in estimates of existing obligations		592,415
New asset retirement obligations	300,980
Liabilities settled	-243,866	-28,700
Accretion expense	211,995	112,686
Total	1,866,770	1,597,661
Less: current portion of asset retirement obligations	-85,846	-107,388
Long-term asset retirement obligations, at the end of the year	$1,780,924	$1,490,273

12_Asset_Retirement_Obligation3

12. Asset Retirement Obligations (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations Details Narrative
Increaseing assets	$300,980
Liabilities settled recognized	243,866	28,700
Abandonment expense		$63,767

13_LongTerm_Debt_Details

13. Long-Term Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery Loan	$8,648,980	$9,057,937
Sovereign Loan	1,638,898
Notre Dame Debt	1,300,000	1,300,000
Capital Leases	466,401
Construction and Funding Agreement		5,747,330
Total	12,054,279	16,105,267
Less: Current portion of long-term debt	-1,245,476	-2,215,918
Long term debt	$10,808,803	$13,889,349

13_LongTerm_Debt_Details_1

13. Long-Term Debt (Details 1) (USD $)	Dec. 31, 2014
Long-Term Debt Details 1
2015	$1,245,476
2016	2,616,167
2017	958,202
2018	517,543
2019	546,736
Subsequent to 2019	6,170,609
long Term Debt Payment, Net	$12,054,279

13_LongTerm_Debt_Details_2

13. Long-Term Debt (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Long-term Debt Details 2
Cost	$538,598
Less: accumulated depreciation
Long-term capital lease obligations, Net	$538,598

13_LongTerm_Debt_Details_3

13. Long-Term Debt (Details 3) (USD $)	Dec. 31, 2014
Long-term Debt Details 3
2015	$171,821
2016	171,821
2017	148,058
2018
2019
Subsequent to 2019
Total future minimum lease payments	491,700
Amount representing interest	-25,299
Present value of minimum lease payments	$466,401

13_LongTerm_Debt_Details_Narra

13. Long-Term Debt (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery outstanding balance	$8,648,980	$9,057,937
Refinery loan accrued interest	47,569	40,132
Construction and Funding Agreement outstanding balance		5,747,330
Construction and Funding Agreement accrued interest		700,597
Notre Dame debt outstanding balance	1,300,000	1,300,000
Notre Dame debt accrued interest	$1,274,789	$1,066,784

15_Treasury_Stock_Details_Narr

15. Treasury Stock (Details Narrative)	Dec. 31, 2014	Dec. 31, 2013
Treasury Stock Details Narrative
Treasury stock	150,000	150,000

16_Concentration_of_Risk_Detai

16. Concentration of Risk (Details) (USD $)	12 Months Ended
16. Concentration of Risk (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Total refined petroleum product sales	$387,304,774	$409,239,747
Concentration Risk	100.00%	100.00%
Atmospheric gas oil
Total refined petroleum product sales	96,027,339	101,955,402
Concentration Risk	24.80%	24.90%
Naphtha
Total refined petroleum product sales	89,700,423	103,980,651
Concentration Risk	23.20%	25.40%
Jet Fuel [Member]
Total refined petroleum product sales	88,479,458	20,048,594
Concentration Risk	22.80%	4.90%
NRLM [Member]
Total refined petroleum product sales	62,729,476	182,513,228
Concentration Risk	16.20%	44.60%
Oil-based mud blendstock [Member]
Total refined petroleum product sales	49,662,414
Concentration Risk	12.80%	0.00%
LPG mix [Member]
Total refined petroleum product sales	705,664	499,277
Concentration Risk	0.20%	0.10%
Reduced crude [Member]
Total refined petroleum product sales		$242,595
Concentration Risk	0.00%	0.10%

16_Concentration_of_Risk_Detai1

16. Concentration of Risk (Details Narrative ) (USD $)	12 Months Ended
16. Concentration of Risk (Details Narrative ) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Concentration Risk	100.00%	100.00%
Sales Revenue [Member] \| Five customers [Member]
Concentration Risk	89.00%	92.00%
Account receivable [Member] \| Five customers [Member]
[custom:AccountsReceivableRisk]	6,400,000	13,400,000

17_Leases_Details

17. Leases (Details) (USD $)	Dec. 31, 2014
Leases Details 1
2015	$116,231
2016	116,231
2017	48,429
Leases Futurre Minimum Payment, Net	$280,891

17_Leases_Details_Narrative

17. Leases (Details Narrative) (USD $)	12 Months Ended
17. Leases (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Leases Details Narrative
Rent expense	$98,876	$113,381

18_Income_Taxes_Details

18. Income Taxes (Details) (USD $)	12 Months Ended
18. Income Taxes (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	($64,258)	$0
State	-108,270	-89,255
Deferred:
Federal	5,760,106
State
Income tax benefit (expense)	$5,587,578	($89,255)

18_Income_Taxes_Details_1

18. Income Taxes (Details 1)	12 Months Ended
18. Income Taxes (Details 1)	Dec. 31, 2014	Dec. 31, 2013
Income Taxes Details 1
Expected tax rate	34.00%	34.00%
Permanent differences	0.00%	0.00%
State tax	1.06%	-2.49%
Federal tax	0.63%	0.00%
Change in valuation allowance	-90.63%	34.00%
Expected tax rate Continuing Operations	-54.94%	-2.49%

18_Income_Taxes_Details_2

18. Income Taxes (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Inventories	$369
Net operating loss and capital loss carryforwards	10,067,144	9,831,410
Start-up costs (Nixon Facility)	1,648,036	1,785,372
Asset retirement obligations liability/deferrred revenue	869,821	645,538
AMT credit	85,098	20,840
Total deferred tax assets	12,670,468	12,283,160
Deferred tax liabilities:
Unrealized hedges	-168,606	-2,363
Basis differences in property and equipment	-4,471,434	-3,163,568
Total deferred tax liabilities	-4,640,040	-3,165,931
Deferred tax assets, net	8,030,428	9,117,229
Less: valuation allowance	-2,270,322	-9,117,229
Deferred tax assets and liabilities, net	$5,760,106

18_Income_Taxes_Details_3

18. Income Taxes (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Income Taxes Details 3
Current deferred tax liabilities, net	($168,237)	($2,363)
Noncurrent deferred tax assets, net	8,198,665	9,119,592
Deferred tax assets, net	8,030,428	9,117,229
Less: valuation allowance	-2,270,322	-9,117,229
Deferred tax assets and liabilities, net	$5,760,106

18_Income_Taxes_Details_Narrat

18. Income Taxes (Details Narrative) (USD $)	Dec. 31, 2014
Income Taxes Details 1
NOLs	$1,300,000

19_Earnings_per_share_Details

19. Earnings per share (Details) (USD $)	12 Months Ended
19. Earnings per share (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net income (loss)	$15,758,756	($3,807,129)
Basic and diluted income (loss) per share
Basic and diluted income (loss) per share	$1.51	($0.36)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,441,464	10,445,883

20_Fair_Value_Measurement_Deta

20. Fair Value Measurement (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Financial liabilties:
Commodity contracts	$495,900	$6,950
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
Financial liabilties:
Commodity contracts	495,900	6,950
Significant Unobservable Inputs (Level 2)
Financial liabilties:
Commodity contracts
Significant Unobservable Inputs (Level 3)
Financial liabilties:
Commodity contracts

24_Fair_Value_Measurement_Deta

24. Fair Value Measurement (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurement Details Narrative
Fair value of longer term debt	$12,054,279	$16,117,151

21_Refined_Petroleum_Products_1

21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Dec. 31, 2014
Refined products - net short (long) positions
Volume in Thousands of barrels
Notional Contract Volumes 2015	115,000
Notional Contract Volumes 2016
Notional Contract Volumes 2017

21_Refined_Petroleum_Products_2

21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Cost of refined products sold	$3,816,871	($103,160)
Commodity Contracts
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$495,900	$6,950

26_Commitments_and_Contingenci

26. Commitments and Contingencies (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Construction and Funding Agreement		$5,747,330