10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended:  September 30, 2014

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _____________ to_____________

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware	73-1268729
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

(713) 568-4725

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	þ
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

Number of shares of common stock, par value $0.01 per share outstanding as of November 14, 2014:  10,446,218

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

FORM 10-Q REPORT INDEX

PART I	FINANCIAL INFORMATION	3
ITEM 1.	FINANCIAL STATEMENTS	3
	Consolidated Balance Sheets (Unaudited)	3
	Consolidated Statements of Operations (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 4.	CONTROLS AND PROCEDURES	43
PART II	OTHER INFORMATION	44
ITEM 1.	LEGAL PROCEEDINGS	44
ITEM 1A.	RISK FACTORS	44
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	44
ITEM 4.	MINE SAFETY DISCLOSURES	44
ITEM 5.	OTHER INFORMATION	45
ITEM 6.	EXHIBITS	45
SIGNATURES		46

Remainder of Page Intentionally Left Blank

2

PART I    FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Blue Dolphin Energy Company & Subsidiaries

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,182,475		$	434,717
Restricted cash		1,005,886			327,388
Accounts receivable		11,428,482			13,487,106
Prepaid expenses and other current assets		181,028			333,683
Deposits		860,498			1,219,660
Inventory		7,566,128			4,686,399
Total current assets		22,224,497			20,488,953
Total property and equipment, net		37,191,958			36,388,666
Surety bonds		850,000			-
Debt issue costs, net		473,186			498,536
Trade name		303,346			303,346
TOTAL ASSETS	$	61,042,987		$	57,679,501
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	20,030,921		$	20,783,541
Accounts payable, related party		1,801,376			3,659,340
Notes payable		1,795,702			11,884
Asset retirement obligations, current portion		107,509			107,388
Accrued expenses and other current liabilities		2,178,424			1,600,444
Interest payable, current portion		49,106			40,272
Long-term debt, current portion		590,098			2,215,918
Total current liabilities		26,553,136			28,418,787
Long-term liabilities:
Asset retirement obligations, net of current portion		1,946,484			1,490,273
Deferred revenues and expenses		734,745			-
Long-term debt, net of current portion		9,948,673			13,889,349
Long-term interest payable, net of current portion		1,222,360			1,767,381
Total long-term liabilities		13,852,262			17,147,003
TOTAL LIABILITIES		40,405,398			45,565,790
Commitments and contingencies
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized;10,596,218 and 10,580,973
shares issued at September 30, 2014 and December 31, 2013, respectively)		105,963			105,810
Additional paid-in capital		36,698,813			36,623,965
Accumulated deficit		(15,367,187	)		(23,816,064	)
Treasury stock, 150,000 shares at cost		(800,000	)		(800,000	)
Total stockholders' equity		20,637,589			12,113,711
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	61,042,987		$	57,679,501

See accompanying notes to consolidated financial statements.

3

Blue Dolphin Energy Company & Subsidiaries

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUE FROM OPERATIONS
Refined product sales	$	87,846,757		$	106,541,284		$	310,938,981		$	320,025,559
Pipeline operations		56,900			78,909			178,793			229,162
Oil and gas sales		-			200			-			200
Total revenue from operations		87,903,657			106,620,393			311,117,774			320,254,921
COST OF OPERATIONS
Cost of refined products sold		83,876,239			105,314,208			292,154,207			317,508,586
Refinery operating expenses		2,496,514			2,629,518			8,092,738			8,099,371
Pipeline operating expenses		50,100			40,813			139,542			122,592
Lease operating expenses		7,041			16,797			21,037			58,088
General and administrative expenses		253,437			387,100			1,049,981			1,333,203
Depletion, depreciation and amortization		393,871			337,156			1,175,643			997,671
Abandonment expense		-			8			-			51,360
Accretion expense		53,731			28,173			158,264			84,513
Total cost of operations		87,130,933			108,753,773			302,791,412			328,255,384
Income (loss) from operations		772,724			(2,133,380	)		8,326,362			(8,000,463	)
OTHER INCOME (EXPENSE)
Tank rental and easement revenue		282,516			278,349			1,055,882			835,048
Interest and other income		1,813			668			45,411			2,480
Interest expense		(214,407	)		(226,374	)		(675,586	)		(788,143	)
Loss on disposal of property and equipment		(4,400	)		-			(4,400	)		-
Total other income		65,522			52,643			421,307			49,385
Income (loss) before income taxes		838,246			(2,080,737	)		8,747,669			(7,951,078	)
Income tax expense, current		(22,199	)		-			(298,792	)		-
Net income (loss)	$	816,047		$	(2,080,737	)	$	8,448,877		$	(7,951,078	)
Income (loss) per common share
Basic	$	0.08		$	(0.20	)	$	0.81		$	(0.76	)
Diluted	$	0.08		$	(0.20	)	$	0.81		$	(0.76	)
Weighted average number of common shares outstanding:
Basic		10,446,218			10,421,731			10,439,684			10,450,906
Diluted		10,446,218			10,421,731			10,439,684			10,450,906

See accompanying notes to consolidated financial statements.

4

Blue Dolphin Energy Company & Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2014			2013
OPERATING ACTIVITIES
Net income (loss)	$	8,448,877		$	(7,951,078	)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization		1,175,643			997,671
Unrealized loss on derivatives		26,150			(297,020	)
Amortization of debt issue costs		25,350			25,350
Amortization of intangible assets		-			9,463
Accretion expense		158,264			84,513
Abandonment costs incurred		-			51,360
Common stock issued for services		75,001			100,000
Loss on disposal of assets		4,400			-
Changes in operating assets and liabilities
Restricted cash		(678,498	)		62,210
Accounts receivable		2,058,624			6,358,937
Prepaid expenses and other current assets		152,655			(186,467	)
Deposits and other assets		(490,838	)		(213	)
Inventory		(2,879,729	)		(2,085,969	)
Accounts payable, accrued expenses and other liabilities		(5,144	)		(3,395,086	)
Accounts payable, related party		(1,857,964	)		1,665,782
Net cash provided by (used in) operating activities		6,212,791			(4,560,547	)
INVESTING ACTIVITIES
Capital expenditures		(1,145,720	)		(1,244,859	)
Proceeds from sale of assets		-			201,000
Net cash used in investing activities		(1,145,720	)		(1,043,859	)
FINANCING ACTIVITIES
Proceeds from issuance of debt		-			5,750,611
Payments on long-term debt		(6,103,131	)		(60,876	)
Proceeds from notes payable		2,000,000			15,032
Payments on notes payable		(216,182	)		(206,445	)
Net cash provided by (used in) financing activities		(4,319,313	)		5,498,322
Net increase (decrease) in cash and cash equivalents		747,758			(106,084	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		434,717			420,896
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,182,475		$	314,812
Supplemental Information:
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		$	-
Financing of capital expenditures via capital lease	$	536,635		$	-
Deferred revenue recognized	$	115,254		$	-
Accrued services payable converted to common stock	$	-		$	50,000
Interest paid	$	1,211,773		$	617,091

See accompanying notes to consolidated financial statements.

5

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(1) Organization

Nature of Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company.  We are primarily an independent refiner and marketer of petroleum products.  Our primary operating asset is a 56-acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  Operations at the Nixon Facility also involve the storage and terminaling of petroleum under third-party lease agreements. 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.

We conduct substantially all of our operations through our wholly-owned subsidiaries. Our operating subsidiaries include:

●   Lazarus Energy, LLC, a Delaware limited liability company (petroleum processing assets) (“LE”);

●   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).

Operating Risks

We had cash and cash equivalents of $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.  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 $10,000,000 (the “Refinery Note”).  In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”).  We are currently making our scheduled payments in accordance with the terms and conditions of the Loan Agreement.  As of December 31, 2013, we were in violation of the current ratio covenant in the Loan Agreement. Effective December 31, 2013, AFNB agreed to waive certain financial maintenance covenants (the “Waiver Agreement”) relating to debt-to-worth and current ratio (the “Financial Maintenance Covenants”) under the Loan Agreement.  As of September 30, 2014 and the date of filing of this report, we were in compliance with the Financial Maintenance Covenants.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

We currently rely on our profit share under the Joint Marketing Agreement dated August 12, 2011 (the “Joint Marketing Agreement”) by and between LE and GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LLC (“Genesis”) and Lazarus Energy Holdings, LLC (“LEH”), our controlling shareholder, to fund our working capital requirements.  GEL is also the exclusive supplier of our crude oil for the Nixon Facility under the Crude Oil and Supply Throughput Services Agreement by and between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”).  During months in which we receive no profit share under the Joint Marketing Agreement, GEL and/or LEH may, but are not required to, fund our working capital requirements. There can be no assurances that either GEL or LEH will continue to fund our working capital requirements.  In the event our working capital requirements are not funded by either our profit share, GEL or LEH, then we may experience a significant and material adverse effect on our operating results.  See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to the end of term for the Joint Marketing Agreement and Crude Supply Agreement.

We believe that our operational strategy, including: (i) increased production of and expansion of our customer base for jet fuel, and (ii) continued refurbishment of key components of the Nixon Facility, including the naphtha stabilizer and depropanizer units will be sufficient to support our operations over the next twelve months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve its anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share, GEL, or LEH, then we may experience a significant and material adverse effect on our operating results, liquidity, and financial condition.

6

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(2) Basis of Presentation

We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. 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.  This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

 (3) 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 generally accepted accounting principles 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 equivalents include 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, exceed insured 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 $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted cash was $1,005,886 and $327,388 at September 30, 2014 and December 31, 2013, respectively. These amounts include 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.

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

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured cash balances of $1,409,238 and $77,388 at September 30, 2014 and December 31, 2013, respectively.

7

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

For the three months ended September 30, 2014, we had ­3 customers that accounted for approximately 71% of our refined petroleum product sales.  These 3 customers represented approximately $6.4 million in accounts receivable at September 30, 2014.  For the three months ended September 30, 2013, we had 4 customers that accounted for approximately 91% of our refined petroleum product sales.  These 4 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

For the nine months ended September 30, 2014, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales.  These 4 customers represented approximately $7.7 million in accounts receivable at September 30, 2014.  For the nine months ended September 30, 2013, we had 5 customers that accounted for approximately 92% of our refined petroleum product sales.  These 5 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

Inventory

Our inventory primarily consists of refined petroleum products.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory 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.

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 in 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 three and nine months ended September 30, 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 U.S. Gulf of Mexico oil and gas properties had no production during the three and nine months ended September 30, 2014 and 2013.  All leases associated with our U.S. 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.

8

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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.

Intangibles – Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with 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 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

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 $473,186 and $498,536 at September 30, 2014 and December 31, 2013, respectively.  Accumulated amortization was $202,794 and $177,445 at September 30, 2014 and December 31, 2013, respectively.

Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 2014.  Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 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 product 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 in cash and in the form of a cash-backed security bond 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 in the form of a cash-backed security bond 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 bond secures.

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.

9

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

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.

In assessing 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.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  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.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical 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 products sold in our consolidated statements of operations using mark-to-market accounting.

10

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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 unaudited 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.

Stock-Based Compensation

In accordance with FASB ASC guidance for stock-based compensation, share-based payments to employees, 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).

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.

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.

11

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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

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 U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.

Segment financials for the three months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Three Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	87,846,757		$	56,900		$	-		$	87,903,657
Operation cost(1)(2)(3)		(86,355,916	)		(110,872	)		(274,674	)		(86,741,462	)
Other non-interest income		282,516			-			-			282,516
EBITDA	$	1,773,357		$	(53,972	)	$	(274,674	)
Depletion, depreciation and amortization											(393,871	)
Interest expense, net											(212,594	)
Income before income taxes										$	838,246
Capital expenditures	$	815,849		$	-		$	-		$	815,849
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $466,821 and an unrealized loss of $70,550.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

12

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Segment financials for the three months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Three Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	106,541,284		$	79,109		$	-		$	106,620,393
Less:  Operation cost(1)(2)(3)		(107,961,900	)		(114,105	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			278,349
EBITDA	$	(1,142,267	)	$	(34,996	)	$	(340,612	)
Depletion, depreciation and amortization											(337,156	)
Interest expense, net											(225,706	)
Loss before income taxes										$	(2,080,737	)
Capital expenditures	$	356,889		$	-		$	-		$	356,889
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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13

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Segment financials for the nine months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Nine Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	310,938,981		$	178,793		$	-		$	311,117,774
Operation cost(1)(2)(3)		(300,291,370	)		(355,645	)		(973,154	)		(301,620,169	)
Other non-interest income		847,549			208,333			-			1,055,882
EBITDA	$	11,495,160		$	31,481		$	(973,154	)
Depletion, depreciation and amortization											(1,175,643	)
Interest expense, net											(630,175	)
Income before income taxes										$	8,747,669
Capital expenditures	$	1,145,720		$	-		$	-		$	1,145,720
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $13,712 and an unrealized loss of $26,150.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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14

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Segment financials for the nine months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Nine Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	320,025,559		$	229,362		$	-		$	320,254,921
Operation cost(1)(2)(3)		(325,625,984	)		(433,065	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			835,048
EBITDA	$	(4,765,377	)	$	(203,703	)	$	(1,198,664	)
Depletion, depreciation and amortization											(997,671	)
Interest expense, net											(785,663	)
Loss before income taxes										$	(7,951,078	)
Capital expenditures	$	1,244,859		$	-		$	-		$	1,244,859
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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15

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(5) Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	September 30,		December 31,
	2014		2013
Prepaid insurance	$	73,278	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		3,750		15,000
Prepaid taxes		-		9,216
Unrealized hedging gains		-		6,950
	$	181,028	$	333,683

(6) Deposits

Deposits consisted of the following:

	September 30,		December 31,
	2014		2013
Utility deposits	$	10,250	$	10,250
Equipment deposits		48,785		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	860,498	$	1,219,660

(7) Inventory

Inventory consisted of the following:

	September 30,		December 31,
	2014		2013
Oil-based mud blendstock	$	778,698	$	-
Naphtha		1,265,891		804,490
Atmospheric gas oil		536,900		575,919
Jet fuel		4,926,222		1,444,399
LPG mix		39,376		28,888
Crude		19,041		19,041
NRLM		-		1,813,662
	$	7,566,128	$	4,686,399

16

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(8) Property, Plant and Equipment, Net

Property, plant and equipment, net, consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery and facilities	$	36,209,053	$	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
		39,861,697		39,150,367
Less:  Accumulated depletion, depreciation and amortization		4,191,256		3,016,713
		35,670,441		36,133,654
Construction in Progress		1,521,517		255,012
Property, Plant and Equipment, Net	$	37,191,958	$	36,388,666

(9) Accounts Payable, Related Party

LEH, our controlling shareholder, owns approximately 81% of our outstanding common stock, par value $0.01 per share (the “Common Stock”).  Jonathan Carroll, Chairman of the Board of Directors (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 a Management Agreement dated February 15, 2012.  On May 12, 2014, the Management Agreement was amended by: (i) extending the term to August 12, 2015, and (ii) changing the name of the agreement from “Management Agreement” to “Operating Agreement” (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 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 three months ended September 30, 2014 and 2013 were $2,496,514 (approximately $2.94 per barrel of throughput) and $2,629,518 (approximately $2.68 per barrel of throughput), respectively.  Aggregate amounts expensed for Services at the Nixon Facility for the nine months ended September 30, 2014 and 2013 were $8,092,738 (approximately $2.78 per barrel of throughput) and $8,099,371 (approximately $2.73 per barrel of throughput).

At September 30, 2014 and December 31, 2013, the amounts outstanding to LEH to fund our working capital requirements were $1,801,376 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.

17

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

 (10) Notes Payable

Notes payable consisted of the following:

	September 30,		December 31,
	2014		2013
Short-Term Notes	$	1,795,702	$	9,379
Short-Term Captial Leases		-		2,505
	$	1,795,702	$	11,884

Short-Term Notes.  On May 2, 2014, LRM entered into a loan and security agreement with Sovereign Bank, a Texas state bank, for a term loan facility in the aggregate amount of $2.0 million (the “Sovereign Note”).  The proceeds of the Sovereign Note are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units.  The Sovereign Note is due in May 2015 and bears interest at 6.00%.  The Sovereign Note 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 Note was $1,795,702 and $0 at September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Sovereign Note in the amount of $8,979 and $0 at September 30, 2014 and December 31, 2013, respectively.

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 September 30, 2014 and December 31, 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 September 30, 2014 and December 31, 2013, respectively.  These capital leases were paid off during the first quarter of 2014.

 (11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following: 

	September 30,		December 31,
	2014		2013
Excise and income taxes payable	$	1,080,413	$	688,754
Genesis crude accrued payable		384,362		-
Transportation and inspection		40,000		100,000
Property taxes		30,109		-
Unrealized hedging loss		19,200		-
Unearned revenue		94,172		302,505
Board of director fees payable		341,250		240,000
Other payable		188,918		269,185
	$	2,178,424	$	1,600,444

18

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(12) 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.

AROs on a roll-forward basis were as follows:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(2,912	)
Accretion expense		158,264
		2,053,993
Less:  current portion of asset retirement obligations		107,509
Asset retirement obligations, long-term balanceat September 30, 2014	$	1,946,484

On February 5, 2014, WBI and BDPL entered into the 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 $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. Once plugging and abandonment work has been completed, the collateral will be released to BDPL.  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 the pipelines.

For the three months ended September 30, 2014 and 2013, we recognized $0 and $8, respectively, in abandonment expense related to our oil and gas properties.  For the nine months ended September 30, 2014 and 2013, we recognized $0 and $51,360, respectively, in abandonment expense related to our oil and gas properties.  AROs for 2013 were associated with our High Island A7 and High Island 37 oil and gas properties. We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

19

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(13) Long-Term Debt

Long-term debt consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery Note	$	8,755,089	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		483,682		-
Construction and Funding Agreement		-		5,747,330
		10,538,771		16,105,267
Less: Current portion of long-term debt		590,098		2,215,918
	$	9,948,673	$	13,889,349

Refinery Note.   The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at September 30, 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 $8,755,089 and $9,057,937 at September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Refinery Note in the amount of $40,127 and $40,132 at September 30, 2014 and December 31, 2013, respectively.  See “Note (1) Organization – Operating Risks” of this report for additional disclosures related to the Refinery Note.

The Loan Agreement has Financial Maintenance Covenants.  As of December 31, 2013, we were in violation of the current ratio covenant in the Loan Agreement. However, the Waiver Agreement waives any default or event of default that may have occurred in relation to LE’s non-compliance with the Financial Maintenance Covenants and is effective through December 31, 2014. As of September 30, 2014 and the date of filing of this report, we were in compliance with the Financial Maintenance Covenants.  Accordingly, the Refinery Note has been classified as long-term on our consolidated balance sheets.

In October 2011, the Refinery Loan Documents were acquired by AFNB.  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.

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 September 30, 2014 and December 31, 2013.  Interest was accrued on the Notre Dame Debt in the amount of $1,222,360 and $1,066,784 at September 30, 2014 and December 31, 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.

20

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Capital Leases.  Long-term capital lease obligations totaled $483,682 and $0 at September 30, 2014 and December 31, 2013. The following is a summary of equipment held under long-term capital leases:

	September 30,		December 31,
	2014		2013
Cost	$	537,130	$	-
Less:  Accumulated depreciation		-		-
	$	537,130	$	-

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 is estimated to be completed and delivered in December 2014. The long-term capital lease obligation requires a monthly payment of $14,332 per month. However, until the equipment is delivered, we are required to make payments of $7,159 per month.

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.  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 September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Construction and Funding Agreement in the amount of $0 and $700,597 at September 30, 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 shall now receive up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement.  In addition, Milam shall release all liens on the Nixon Facility.  See “Part I, Item 1. Financial Statements - Note (22) Commitments and Contingencies” of this report for additional disclosures related to the Construction and Funding Agreement and our relationship with Genesis.

(14) 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 merger with LE, all employees of Blue Dolphin became employees of LEH effective February 15, 2012.  Therefore, all options outstanding for Blue Dolphin employees were cancelled 90 days following the effective date of the reverse merger.  At September 30, 2014, there were no options outstanding, no options exercisable or no shares of common stock reserved for issuance under the 2000 Stock Incentive Plan.

(15) Treasury Stock

In March, 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.  As of September 30, 2014 and December 31, 2013, we had 150,000 shares of treasury stock.

21

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(16) Concentration of Risk

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 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 (2) Basis of Presentation” of this report for additional disclosures related to significant customers.

Sales by Product. All of our refined petroleum products are currently sold in the United States. The following table summarizes the percentages of all refined petroleum products sales to total sales:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
LPG mix		0.2	%		0.0	%		0.2	%		0.0	%
Naphtha		21.8	%		24.3	%		23.0	%		25.6	%
Jet fuel		29.6	%		4.8	%		23.3	%		1.6	%
NRLM		0.0	%		44.9	%		15.8	%		48.2	%
Oil-based mud blendstock		25.1	%		0.0	%		12.7	%		0.0	%
Atmospheric gas oil		23.3	%		26.0	%		25.0	%		24.5	%
Reduced crude		0.0	%		0.0	%		0.0	%		0.1	%
		100.0	%		100.0	%		100.0	%		100.0	%

On May 31, 2014, the Nixon Facility discontinued production of Non-Road, Locomotive and Marine diesel (“NRLM,” also commonly referred to as low-sulfur diesel).  On June 1, 2014, the Nixon Facility began producing oil-based mud blendstock, a non-fuel petroleum product.  The shift in product slate from NRLM to oil-based mud blendstock was the result of an Environmental Protection Agency (“EPA”) mandate originally instituted in June 2004 and amended in December 2009 that required a reduction in the sulfur content found in all transportation related diesel fuels. Specific provisions of the EPA standards, as revised, required NRLM produced by small refiners to meet a maximum specification of 15 parts per million of sulfur by June 1, 2014.  The Nixon Facility is currently not equipped to produce transportation related products at the EPA’s lower sulfur content standard.

The Nixon Facility began producing jet fuel in mid-September 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.

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement.  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.

(17) Leases

We are currently under a ten-year lease agreement expiring in 2017 for office space in downtown Houston, Texas, which serves as our company headquarters.  We are committed to pay a portion of the related actual operating expenses under the lease agreement, which includes free rent periods or escalating rent payment provisions.  We recognize rent expense under such arrangements on a straight-line basis. For the three months ended September 30, 2014 and 2013, rent expense for the office lease was $26,129 and $25,161, respectively. For the nine months ended September 30, 2014 and 2013, rent expense for the office lease was $77,787 and $76,382, respectively.

22

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(18) Income Taxes

LE is a limited liability company and, prior to our reverse merger with LE on February 15, 2012, LE’s taxable income or net operating losses (“NOLs”) flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. As a result of the reverse merger, LE became a subsidiary of Blue Dolphin and LE’s taxable income or loss flowed through to Blue Dolphin for federal and state income tax purposes.

Section 382 of the Internal Revenue Code imposes a limitation on the use of Blue Dolphin’s NOLs generated prior to the reverse merger.  The amount of NOLs subject to such limitation is approximately $18.8 million, of which approximately $1.9 million is projected to be utilized for the nine months ended September 30, 2014.  NOLs generated subsequent to the reverse merger through December 31, 2013 of approximately $14.9 million are not subject to any such limitation. Approximately $5.7 million of the post-merger NOLs are projected to be utilized for the nine months ended September 30, 2014.  As of September 30, 2014 and December 31, 2013, our deferred tax assets were fully reserved against due to the uncertainty of their use as a result of net losses prior to 2014.

For the three months ended September 30, 2014 and 2013, income tax expense was $22,199 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $1,395 was the result of alternative minimum tax.

For the nine months ended September 30, 2014 and 2013, income tax expense was $298,792 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $152,759 was the result of alternative minimum tax.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.  At September 30, 2014, we accrued $146,033 in TMT.

(19) Earnings Per Share

The following table provides reconciliation between basic and diluted income (loss) per share:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Net income (loss)	$	816,047	$	(2,080,737	)	$	8,448,877	$	(7,951,078	)
Basic and diluted income (loss) per share	$	0.08	$	(0.20	)	$	0.81	$	(0.76	)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,446,218		10,421,731			10,439,684		10,450,906

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 three and nine months ended September 30, 2014 is the same as there were no stock options or other dilutive instruments outstanding.  Diluted EPS for the three and nine months ended September 30, 2013 excludes stock options outstanding as they would be anti-dilutive.

23

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(20) 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 can execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity risks associated with our refined petroleum products and crude oil inventory and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil inputs. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreements 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 September 30, 2014 and December 31, 2013 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at September 30, 2014 and December 31, 2013 was $12,334,473 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 September 30, 2014 and the basis for that measurement:

				Fair Value Measurement at September 30, 2014 Using
Financial assets (liabilities):	Carrying Value at September 30, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(19,200	)	$	(19,200	)	$	-	$	-

			Fair Value Measurement at December 31, 2013 Using
Financial assets (liabilities):	Carrying Value at December 31, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	6,950	$	6,950	$	-	$	-

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

24

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(21) Refined Petroleum Products and Crude Oil Inventory Risk Management

Under our refined petroleum products and crude oil inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations in our inventory. The physical 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 and crude oil 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 September 30, 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):

Inventory positions (futures):	2014		2015		2016
Refined petroleum products and crude oil -net short positions		45,000		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at September 30, 2014 and December 31, 2013: 

		Fair Value
		September 30,
Asset Derivatives	Balance Sheets Location	2014			2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	(19,200	)	$	6,950

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013: 

		Gain (Loss) Recognized
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Derivatives	Statements of Operations Location	2014		2013			2014			2013
Commodity contracts	Cost of refined products sold	$	396,271	$	(297,179	)	$	(12,438	)	$	(330,320	)

25

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(22) 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 to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil 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 has 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) 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 will 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 pursuant to the Crude Supply Agreement) as follows:

26

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(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.

27

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(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 September 30, 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

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.

28

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Supplemental Pipeline Bonds

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 $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  The bond increased the collateral held by a surety company relating to supplemental pipeline bonds issued on behalf of BDPL to satisfy the bonding requirements of the Bureau of Ocean Energy Management.  These supplemental pipeline bonds are intended to secure the performance of BDPL’s plugging and abandonment obligations with respect to pipeline segments in federal waters of the U.S. Gulf of Mexico.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

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

Master Easement Agreement - BDPL and FLNG

On October 30, 2014, FLNG made a second payment of $250,000 to BDPL. Such 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.  See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to the Master Easement Agreement.

Remainder of Page Intentionally Left Blank

29

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with the risk factors, unaudited consolidated financial statements and notes included hereto, as well as the audited consolidated financial statements and notes thereto included in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013  and previously filed Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014.  In this document, the words “Blue Dolphin,” “we,” “us” and “our” refer to Blue Dolphin Energy Company and its subsidiaries.

Forward Looking Statements

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2014, and in particular under the sections entitled “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 1A. Risk Factors” are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized, or materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

● fluctuations of crude oil inventory costs and refined petroleum products inventory prices and their effect on our refining margins;

● changes in the underlying demand for our products;

● our dependence on Genesis Energy, LLC (“Genesis”) and its affiliates for continued financing, sourcing of crude oil inventory and marketing of our refined petroleum products;

● the early termination of our agreements with Genesis and its affiliates;

● our dependence on Lazarus Energy Holdings, LLC (“LEH”), our controlling shareholder, for continued financing and management of all of our subsidiaries and the operation of all of our assets, including the Nixon Facility, pursuant to the Operating Agreement;

● our ability to generate sufficient funds from operations or obtain financing from other sources;

● potential downtime of the Nixon Facility, which could result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations;

● failure to comply with certain financial maintenance covenants related to certain of our long-term indebtedness;

● regulatory changes that reduce the allowable sulfur content for commercially sold diesel in the United States, which will require us to incur significant capital upgrades and could have a material adverse effect on our results of operations, financial condition and cash flows;

● availability and cost of renewable fuels for blending and Renewable Identification Numbers (“RINs”) to meet Renewable Fuel Standards ("RFS") obligations;

● strict laws and regulations regarding employee and business process safety to which we are subject, the compliance failure of which could have a material adverse effect on our results of operations and financial condition;

● potential increased indebtedness, which may reduce our financial flexibility;

● regulatory restrictions on greenhouse gas emissions, which could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition;

● access to less than desired levels of crude oil for processing at the Nixon Facility;

● our dependence on a small number of customers for a large percentage of our revenues;

● accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our operations;

● the geographic concentration of the Nixon Facility, which creates a significant exposure risk to the regional economy;

● competition from larger companies;

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● infrastructure limitations;

● dangers inherent in our operations, such as fires and explosions, which could cause disruptions and expose us to potentially significant losses, costs and liabilities and significantly reduce our liquidity;

● the effects of Genesis’ hedging of our refined petroleum products and crude oil inventory and exposure to the risks associated with volatile crude oil prices;

● retention of key personnel;

● insurance coverage that may be inadequate or expensive;

● our potential reorganization from a publicly traded “C” corporation to a publicly traded master limited partnership;

● performance of third-party operators for our oil and gas properties;

● costs and collateral associated with abandonment of our pipelines and oil and gas properties;

● changes in and compliance with taxes, which could adversely affect our performance; and

● changes in the general economic conditions.

Any one of these factors or a combination of these factors could materially affect our future results of operations and could influence whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

Company Overview

Blue Dolphin Energy Company (www.blue-dolphin-energy.com), a Delaware corporation (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) was formed in 1986 as a holding company. We conduct substantially all of our operations through our wholly-owned subsidiaries.  We are primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 56-acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  Operations at the Nixon Facility also involve the storage and terminaling of petroleum under third-party lease agreements.  We also own and operate pipeline assets and have leasehold interests in oil and gas properties, which are considered non-core to our business.

Refinery Operations

Our primary business is the refining of crude oil and condensate into marketable finished and intermediate products at the Nixon Facility, which has a current operating capacity of approximately 15,000 barrels (“bbls”) per day (“bpd”). The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, jet fuel treater, approximately 120,000 bbls of crude oil storage capacity, approximately 178,000 bbls of refined product storage capacity and related loading and unloading facilities and utilities.

The Nixon Facility is operated as a “topping unit,” processing light crude oil and condensate from the Eagle Ford Shale formation in South Texas.  We purchase the light crude oil and condensate for the Nixon Facility under an exclusive supply agreement with GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis.  The light crude oil and condensate is refined into finished products such as jet fuel, the Nixon Facility’s most recent saleable product, and intermediate products such as naphtha, liquefied petroleum gas (“LPG”), atmospheric gas oil and oil-based mud blendstock.  Finished products are sold in nearby markets and intermediate products are sold to wholesalers and nearby refineries for further blending and processing.  Crude oil and condensate is currently received at the Nixon Facility by truck, however, the facility has the ability to receive feedstock by pipeline.  Our refined products are sold and delivered primarily by truck.

Pipeline Transportation

Our pipeline transportation operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines, as well as leasehold interests in oil and natural gas properties, in the U.S. Gulf of Mexico. Our pipeline transportation operations represented less than 1% of total revenue for the three and nine months ended September 30, 2014 and 2013.

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Owned and Leased Assets

We own, lease, and have leasehold interests in the properties listed below:

Property	Business Segment(s)	Acres	Owned / Leased	Location
Nixon  Facility	Refinery Operations	56	Owned	Nixon, Wilson County, Texas
Freeport Facility	Pipeline Transportation	193	Owned	Freeport, Brazoria County, Texas
Pipelines and Oil and Gas Properties	Pipeline Transportation	--	Owned, Leasehold Interests	U.S. Gulf of Mexico
Corporate Headquarters	Corporate and Other	--	Lease	Houston, Harris County, Texas

LEH manages and operates all of our properties and is reimbursed for their management and operation under the Operating Agreement.  We believe that our properties are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business.

Key Operating Statistics

Key operational statistics for our core business segment, refinery operations, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Nixon Facility
Operating days		78			90			252			265
Total refinery throughput(1)
bbls		849,402			979,807			2,909,669			2,967,469
bpd		10,890			10,887			11,546			11,198
Capacity utilization rate		73	%		73	%		77	%		75	%
Total refinery production
bbls		831,771			963,645			2,855,054			2,906,873
bpd		10,664			10,707			11,330			10,969
Capacity utilization rate		71	%		71	%		76	%		73	%

(1)   Total refinery throughput includes crude oil and condensate and other feedstocks.

Major Influences on Results of Operations

The safe, efficient and reliable operation of the Nixon Facility is critical to our financial performance.  Any adverse financial impact of a maintenance turnaround or significant capital improvement project is mitigated through a diligent planning process that considers expectations for product availability, seasonality, margin environment and the availability of resources to perform the required work.  Periodic maintenance and repairs are generally performed annually, depending on the processing units involved.

Earnings and cash flow from our refining operations are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined petroleum products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products, which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of imports, marketing of competitive fuels and government regulation.

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We monitor our per barrel refinery operating margins in order to measure our operating performance. We calculate the per barrel operating margin for the Nixon Facility by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (excluding any substantial unrealized hedge positions and certain inventory adjustments).

The Nixon Facility is capable of processing substantial volumes of low-sulfur crude oil (sweet crude) and condensate to produce a high percentage of light, higher valued refined petroleum products. Sweet crude and condensate derived from surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s input.

The nature of our business requires us to maintain access to substantial quantities of crude oil and refined product inventories. Crude oil and refined petroleum products are essentially commodities, and we have no control over the changing market value of these inventories. We utilize an inventory risk management policy in which derivative instruments may be used as economic hedges to reduce our crude oil and refined petroleum products inventory commodity price risk.

Relationship with Genesis

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

● the Crude Oil Supply and Throughput Services Agreement by and between GEL and LE dated August 12, 2011 (the “Crude Supply Agreement”);

● the Construction and Funding Contract by and between LE and Milam Services, Inc. (“Milam”), an affiliate of Genesis, dated August 12, 2011 (the “Construction and Funding Agreement”); and

● the Joint Marketing Agreement by and between GEL and LE dated August 12, 2011 (as subsequently amended, the “Joint Marketing Agreement”).

The principal balance outstanding on the Construction and Funding Agreement was $0 and $5,747,330 at September 30, 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.  See “Part I, Item 1. Financial Statements - Note (22) Commitments and Contingencies” of this report for additional disclosures related to our relationship with Genesis.

Results of Operations

Three Months Ended September 30, 2014 (the "Current Quarter") Compared to Three Months Ended September 30, 2013 (the "Prior Quarter").

Nixon Facility Operational Update.  The Nixon Facility, which was refurbished and began operations in February 2012, has been operating for approximately two and a half years.  The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations.  Downtime may result in lost margin opportunity, increased maintenance expense, and a reduction in cash available for payment of our obligations.

The Nixon Facility operated for a total of 78 days at 73% of operating capacity during the Current Quarter compared to a total of 90 days at 73% of operating capacity during the Prior Quarter.  This represented 12 fewer operating days in the Current Quarter compared to the Prior Quarter.  The Nixon Facility experienced 14 calendar days of downtime in the Current Quarter primarily related to repair of an overhead accumulator compared to two calendar days of downtime in the Prior Quarter for non-routine maintenance.

Summary. For the Current Quarter, we reported net income of $816,047, or an income of $0.08 per share, compared to a net loss of $2,080,737, or a loss of $0.20 per share, for the Prior Quarter.  The net income in the Current Quarter was primarily attributable to favorable refining margins and improved product mix related to jet fuel production.

Total Revenue from Operations. For the Current Quarter, we had total revenue from operations of $87,903,657 compared to total revenue from operations of $106,620,393 for the Prior Quarter.  The nearly 18% decrease in total revenue from operations was primarily the result of operating 12 fewer days and having lower refined product sales in the Current Quarter compared to the Prior Quarter.  Substantially all of our revenue in the Current Quarter came from refined product sales, which generated revenue of $87,846,757, or more than 99% of total revenue from operations, compared to $106,541,284, or more than 99% of total revenue from operations, in the Prior Quarter.

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Cost of Refined Products Sold. Cost of refined petroleum products sold was $83,876,239 for the Current Quarter compared to $105,314,208 for the Prior Quarter.  The approximate 20% decrease in cost of refined products sold was primarily the result of a decrease in the average price of crude oil and operating 12 fewer days in the Current Quarter compared to the Prior Quarter.

Refinery Operating Expenses. We recorded refinery operating expenses of $2,496,514 in the Current Quarter, all of which were for services provided to us by LEH to manage and operate Blue Dolphin’s assets pursuant to the Operating Agreement with LEH.  For the Prior Quarter, we recorded refinery operating expenses of $2,629,518.  The approximate 5% decrease in refinery operating expenses in the Current Quarter compared to the Prior Quarter was primarily the result of a decline in total refinery production.  See “Part I, Item 1. Financial Statements - Note (9), Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement.

General and Administrative Expenses. We incurred general and administrative expenses of $253,437 in the Current Quarter compared to $387,100 in the Prior Quarter.  The nearly 35% decrease in general and administrative expenses in the Current Quarter compared to the Prior Quarter was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $393,871 in the Current Quarter compared to $337,156 in the Prior Quarter.  The nearly 17% increase in depletion, depreciation and amortization expenses for the Current Quarter compared to the Prior Quarter primarily related to depreciable refinery assets placed in service.

Other Income. We recognized $282,516 in tank rental and easement revenue in the Current Quarter compared to $278,349 in the Prior Quarter.  The approximate 2% increase in tank rental and easement revenue in the Current Quarter compared to the Prior Quarter was primarily a result of slightly higher tank rental revenue.

Nine Months Ended September 30, 2014 (the "Current Nine Months") Compared to Nine Months Ended September 30, 2013 (the "Prior Nine Months").

Nixon Facility Operational Update.  The Nixon Facility, which was refurbished and began operations in February 2012, has been operating approximately two and a half years.The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations.  Downtime may result in lost margin opportunity, increased maintenance expense, and a reduction in cash available for payment of our obligations.

The Nixon Facility operated for a total of 252 days at 77% of operating capacity during the Current Nine Months compared to a total of 265 days at 75% of operating capacity during the Prior Nine Months.  This represented 13 fewer operating days in the Current Nine Months compared to the Prior Nine Months.  The Nixon Facility experienced 21 calendar days of downtime in the Current Nine Months related to a planned maintenance turnaround and repair of an overhead accumulator compared to 8 calendar days of downtime in the Prior Nine Months for a planned maintenance turnaround.

Summary.  For the Current Nine Months, we reported net income of $8,448,877, or an income of $0.81 per share, compared to a net loss of $7,951,078 or a loss of $0.76 per share, for the Prior Nine Months.  The increase in net income in the Current Nine Months was primarily attributable tofavorable refining margins and improved product mix related to jet fuel production.

Total Revenue from Operations. For the Current Nine Months, we had total revenue from operations of $311,117,774 compared to total revenue from operations of $320,254,921 for the Prior Nine Months.   The nearly 3% decrease in total revenue from operations was primarily the result of decreased total refinery throughput in the Current Nine Months compared to the Prior Nine Months. Substantially all of our revenue in the Current Nine Months came from refined product sales, which generated revenue of $310,938,981, or more than 99% of total revenue from operations, compared to $320,025,559, or more than 99% of total revenue from operations, in the Prior Nine Months.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $292,154,207 for the Current Nine Months compared to $317,508,586 for the Prior Nine Months.  The 8% decrease in cost of refined products sold was primarily the result of a decrease in the average price of crude oil and operating fewer days in the Current Nine Months compared to the Prior Nine Months.

Refinery Operating Expenses. We recorded refinery operating expenses of $8,092,738 in the Current Nine Months, all of which were for services provided to us by LEH to manage and operate Blue Dolphin’s assets pursuant to the Operating Agreement with LEH.  For the Prior Nine Months, we recorded refinery operating expenses of $8,099,371.  See “Part I, Item 1. Financial Statements - Note (9), Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement.

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General and Administrative Expenses. We incurred general and administrative expenses of $1,049,981 in the Current Nine Months compared to $1,333,203 in the Prior Nine Months.  The more than 21% decrease in general and administrative expenses in the Current Nine Months compared to the Prior Nine Months was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $1,175,643 in the Current Nine Months compared to $997,671 in the Prior Nine Months.  The approximate 18% increase in depletion, depreciation and amortization expenses for the Current Nine Months compared to the Prior Nine Months primarily related to depreciable refinery assets placed in service.

Other Income. We recognized $1,055,882 in tank rental and easement revenue in the Current Nine Months compared to $835,048 in the Prior Nine Months.  The approximate 26% increase in tank rental and easement revenue in the Current Nine Months compared to the Prior Nine Months was primarily a result of fees received from FLNG Land, II, Inc., a Delaware corporation (“FLNG”), pursuant to a Master Easement Agreement whereby BDPL is providing FLNG with uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG.

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Earnings Before Interest, Income Taxes and Depreciation (“EBITDA”)

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 U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.  We have reclassified certain prior year amounts to conform to our 2014 presentation.

Management uses EBITDA, a non-GAAP financial measure, to assess the operating results and effectiveness of our business segments, which consist of our consolidated businesses and investments. We believe EBITDA is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by management. Net income (loss) is adjusted for income taxes, interest expense (or income), depletion, depreciation, and amortization. Management excludes these items so that investors may evaluate our current operating results without regard to our financing methods or capital structure. We understand that EBITDA may not be comparable to measurements used by other companies. Additionally, EBITDA should be considered in conjunction with net income (loss) and other performance measures such as operating cash flows.

For the Current Quarter, our Refinery Operations business segment had EBITDA of $1,773,357 compared to a negative EBITDA of $1,142,267 for the Prior Quarter.  For the Current Nine Months, our Refinery Operations business segment had EBITDA of $11,495,160 compared to a negative EBITDA of $4,765,377 for the Prior Nine Months.  Following is a reconciliation of EBITDA and identifiable assets by business segment for the three and nine months ended September 30, 2014 (and at September 30, 2014) and the three and nine months ended September 30, 2013 (and at September 30, 2013):

	Three Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	87,846,757		$	56,900		$	-		$	87,903,657
Operation cost(1)(2)(3)		(86,355,916	)		(110,872	)		(274,674	)		(86,741,462	)
Other non-interest income		282,516			-			-			282,516
EBITDA	$	1,773,357		$	(53,972	)	$	(274,674	)	$	1,444,711
Depletion, depreciation and amortization											(393,871	)
Interest expense, net											(212,594	)
Income before income taxes										$	838,246
Capital expenditures	$	815,849		$	-		$	-		$	815,849
Identifiable assets (4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $466,821 and an unrealized loss of $70,550.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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	Three Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	106,541,284		$	79,109		$	-		$	106,620,393
Operation cost(1)(2)(3)		(107,961,900	)		(114,105	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			278,349
EBITDA	$	(1,142,267	)	$	(34,996	)	$	(340,612	)	$	(1,517,875	)
Depletion, depreciation and amortization											(337,156	)
Interest expense, net											(225,706	)
Loss before income taxes										$	(2,080,737	)
Capital expenditures	$	356,889		$	-		$	-		$	356,889
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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	Nine Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	310,938,981		$	178,793		$	-		$	311,117,774
Operation cost(1)(2)(3)		(300,291,370	)		(355,645	)		(973,154	)		(301,620,169	)
Other non-interest income		847,549			208,333			-			1,055,882
EBITDA	$	11,495,160		$	31,481		$	(973,154	)	$	10,553,487
Depletion, depreciation and amortization											(1,175,643	)
Interest expense, net											(630,175	)
Income before income taxes										$	8,747,669
Capital expenditures	$	1,145,720		$	-		$	-		$	1,145,720
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $13,712 and an unrealized loss of $26,150.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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	Nine Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	320,025,559		$	229,362		$	-		$	320,254,921
Operation cost(1)(2)(3)		(325,625,984	)		(433,065	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			835,048
EBITDA	$	(4,765,377	)	$	(203,703	)	$	(1,198,664	)	$	(6,167,744	)
Depletion, depreciation and amortization											(997,671	)
Interest expense, net											(785,663	)
Loss before income taxes										$	(7,951,078	)
Capital expenditures	$	1,244,859		$	-		$	-		$	1,244,859
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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Critical Accounting Policies

Long-Lived Assets.

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and included in the Operating Agreement with LEH (see “Part I, Item 1. Financial Statements – 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 three and nine months ended September 30, 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 U.S. Gulf of Mexico oil and gas properties were uneconomical for the three and nine months ended September 30, 2014 and 2013.  All leases associated with our U.S. Gulf of Mexico oil and gas properties have expired.

Pipelines and Facilities. Pipelines and facilities have historically been recorded at cost.   We record pipelines and facilities assets 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.

Revenue Recognition. We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil. Revenue from refined product 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.

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.

40

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.

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.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

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.

In assessing 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.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.

Recently Adopted Accounting Guidance

The guidance issued by the FASB during the three and nine months ended September 30, 2014 is not expected to have a material effect on our consolidated financial statements.

Remainder of Page Intentionally Left Blank

41

Liquidity and Capital Resources

Sources and Uses of Cash.

	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2014			2013			2014			2013
Cash flow from operations
Adjusted income (loss) from continuing operations	$	1,347,320		$	(1,738,670	)	$	9,913,956		$	(6,979,741	)
Change in assets and current liabilities		(480,266	)		333,837			(3,701,165	)		2,419,194
Total cash flow from operations		867,054			(1,404,833	)		6,212,791			(4,560,547	)
Cash inflows (outflows)
Proceeds from issuance of long-term debt		-			2,045,420			-			5,750,611
Payments on long term debt		(156,230	)		-			(6,103,131	)		(60,876	)
Capital expenditures		(815,849	)		(356,889	)		(1,145,720	)		(1,244,859	)
Proceeds from sale of assets		-			-			-			201,000
Proceeds from notes payable		-			-			2,000,000			15,032
Payments on notes payble		(153,699	)		(149,705	)		(216,182	)		(206,445	)
Total cash outflows		(1,125,778	)		1,538,826			(5,465,033	)		4,454,463
Total change in cash flows	$	(258,724	)	$	133,993		$	747,758		$	(106,084	)

Our available cash was $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.  We are currently relying on our profit share, GEL and LEH to fund our working capital requirements. As of September 30, 2014, we repaid all amounts advanced under the Construction and Funding Agreement. In accordance with the Joint Marketing Agreement, once the obligations under the Construction and Funding Agreement have been paid in full, the respective share of Gross Profits paid out to LE and Genesis reverses whereby LE receives a majority of the Gross Profits as its share under the Joint Marketing Agreement. The increase in LE’s Profit Share will subsequently lead to higher cash flow generation, liquidity, ability to fund working capital requirements, and an overall stronger financial position.

We are dedicated to maintaining safe, efficient and reliable refinery operations, improving liquidity and profitability, and focusing on safety and environmental stewardship.   In 2014, we plan to: (i) improve process safety management (“PSM”) standards and develop a PSM program at the Nixon Facility, which is designed to address all aspects of Occupational Safety and Health Administration guidelines for developing and maintaining a comprehensive PSM program, (ii) significantly increase our production of and expand our customer base for jet fuel, and (iii) continue with refurbishment of key components of the Nixon Facility, including the naphtha stabilizer and depropanizer units, which we anticipate will improve the overall quality of the naphtha that we produce, allow higher recovery of lighter products that can be sold as a LPG mix, and increase the amount of throughput that can be processed by the Nixon Facility.  See “Part I, Item 1. Financial Statements - Note (10) Notes Payable” of this report for additional disclosures related to refurbishment of the naphtha stabilizer and depropanizer units.

We believe that our operational strategy will be sufficient to support our operations over the next 12 months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive, and other factors beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes, or that GEL and/or LEH will continue to fund our working capital requirements during months in which we have operational losses.  In the event our operational strategy is not successful, or our working capital requirements are not funded by either our profit share, GEL, or LEH, then we may experience a significant and material adverse effect on our operating results, liquidity, and financial condition.  For risk factors related to working capital, liquidity and Nixon Facility downtime, see “Part I, Item 1A. Risk Factors” in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and “Part II, Item 1A. Risk Factors” in our previously filed Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014.

For the Current Quarter, we experienced positive cash flow from operations of $867,054.  For the Prior Quarter, we experienced negative cash flow from operations of $1,404,833. This represented an increase in cash flow from operations of $2,271,887 for the Current Quarter compared to the Prior Quarter, which was primarily due to improved refining margins.  For the Current Nine Months, we experienced positive cash flow from operations of $6,212,791.  For the Prior Nine Months, we experienced negative cash flow from operations of $4,560,547. This represented an increase in cash flow from operations of $10,773,338 for the Current Nine Months compared to the Prior Nine Months, which was primarily due to improved refining margins.

42

Payments on long-term debt in the Current Quarter and Prior Quarter totaled $156,230 and $0, respectively.   Payments on long-term debt in the Current Nine Months and Prior Nine Months totaled $6,103,131 and $60,876, respectively.  The principal balance owed to Milam under the Construction and Funding Agreement was $0 and $5,747,330, including deficit amounts, at September 30, 2014 and December 31, 2013, respectively.

Capital expenditures in the Current Quarter and Prior Quarter totaled $815,849 and $356,889, respectively.  Capital expenditures in the Current Nine Months and Prior Nine Months totaled $1,145,720 and $1,244,859, respectively.  Capital expenditures in both comparative periods primarily related to investments in the Nixon Facility.  We expect to fund additional capital expenditures at the Nixon Facility primarily throughcash from operations or other borrowings.   On May 2, 2014, Lazarus Refining & Marketing, LLC (“LRM”) entered into a loan and security agreement with Sovereign Bank, a Texas state bank, for a term loan facility in the aggregate amount of $2.0 million (the “Sovereign Note”).  The proceeds of the Sovereign Note are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units.  The principal balance outstanding on the Sovereign Note was $1,795,702 and $0 at September 30, 2014 and December 31, 2013, respectively.

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the three and nine months ended September 30, 2014 and 2013.  All leases associated with our U.S. Gulf of Mexico oil and gas properties have expired.  For the Current Quarter and Prior Quarter, we recognized $0 and $8, respectively, in abandonment expense related to our oil and gas properties.  For the Current Nine Months and Prior Nine Months, we recognized $0 and $51,360, respectively, in abandonment expense related to our oil and gas properties.  Abandonment expense in 2013 primarily related to plugging and abandonment costs associated with our High Island A-7 and High Island 37 oil and gas properties.  We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs.

The principal balance outstanding on the Refinery Note was $8,755,089 and $9,057,937 at September 30, 2014 and December 31, 2013, respectively. On September 1, 2013, AFNB and LE agreed to amend 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.

The principal balance outstanding on the Notre Dame Debt was $1,300,000 at September 30, 2014 and December 31, 2013. There are no financial maintenance covenants associated with this debt.

See “Part I, Item 1. Financial Statements - Note (13) Long-Term Debt” of this report for additional disclosures related to our long-term debt obligations.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”).  We have inadequate personnel resources to handle complex accounting transactions and ensure complete segregation of duties within the accounting function. Additionally, we lack formally documented accounting policies and procedures.  The combination of these control deficiencies resulted in a material weakness in our internal control over financial reporting.

43

Based on that evaluation, our Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer) concluded that our disclosure controls and procedures were ineffective as of September 30, 2014.   Our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), require us to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the  Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

The effectiveness of any system of controls and procedures is subject to certain limitations, and, as a result, there can be no assurance that our controls and procedures will detect all errors or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be attained.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the three and nine months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. Vendors have placed mechanic’s liens on the Nixon Facility as protection during construction activities. Management does not believe that such liens have a material adverse effect on our results of operations.

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and “Part II, Item 1A. Risk Factors” in our previously filed Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014.  These risks and uncertainties could materially and adversely affect our business, financial condition and results of operations.  Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business.  There have been no material changes in our assessment of our risk factors from those set forth in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2013 and our previously filed Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

See “Notes (10) Notes Payable and (13) Long-Term Debt” in Part I. Financial Information, Item 1. Financial Statements – Notes to Consolidated Financial Statements (Unaudited) of this report for disclosures related to defaults on debt.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

44

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

(a)  Exhibits:

The following exhibits are filed herewith:

No.  Description 

31.1 Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Schema Document.

101.CAL XBRL Calculation Linkbase Document.

101.LAB XBRL Label Linkbase Document.

101.PRE XBRL Presentation Linkbase Document.

101.DEF XBRL Definition Linkbase Document.

Remainder of Page Intentionally Left Blank 

45

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BLUE DOLPHIN ENERGY COMPANY
Date: November 14, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board,
		Chief Executive Officer, President,
		Assistant Treasurer and Secretary
		(Principal Executive Officer)

Date: November 14, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer,
		Treasurer and Assistant Secretary
		(Principal Financial Officer)

46

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.   The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;

5.   The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.   The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;

5.   The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2014 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2014 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 14, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

16. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 2014

Concentration Of Risk Tables

Percentages of all refined petroleum products sales to total sales

The following table summarizes the percentages of all refined petroleum products sales to total sales:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
LPG mix		0.2	%		0.0	%		0.2	%		0.0	%
Naphtha		21.8	%		24.3	%		23.0	%		25.6	%
Jet fuel		29.6	%		4.8	%		23.3	%		1.6	%
NRLM		0.0	%		44.9	%		15.8	%		48.2	%
Oil-based mud blendstock		25.1	%		0.0	%		12.7	%		0.0	%
Atmospheric gas oil		23.3	%		26.0	%		25.0	%		24.5	%
Reduced crude		0.0	%		0.0	%		0.0	%		0.1	%
		100.0	%		100.0	%		100.0	%		100.0	%

XML

12. Asset Retirement Obligations (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Asset Retirement Obligations Details
Asset retirment obligations at December 31, 2013			$ 1,597,661
New asset retirement obligations			300,980
Asset retirement obligation payments/liabilities settled			(2,912)
Accretion expense	53,731	28,173	158,264	84,513
Asset retirement obligations as of September, 30 2014	2,053,993		2,053,993
Less: current portion of asset retirement obligations	107,509		107,509		107,388
Asset retirement obligations, long-term balance at September 30, 2014	$ 1,946,484		$ 1,946,484		$ 1,490,273

XML

7. Inventory (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Oil-based mud blendstock	$ 778,698
Naphtha	1,265,891	804,490
Atmospheric gas oil	536,900	575,919
Jet fuel	4,926,222	1,444,399
LPG mix	39,376	28,888
Crude	19,041	19,041
NRLM		1,813,662
Inventories, Net	$ 7,566,128	$ 4,686,399

XML

12. Asset Retirement Obligations (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligations Details Narrative
Abandonment expense	$ 0	$ 8		$ 51,360

XML

5. Prepaid Expenses and Other Current Assets (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 73,278	$ 165,004
Prepaid professional fees	104,000	104,000
Prepaid loan closing fees		33,513
Prepaid listing fees	3,750	15,000
Prepaid taxes		9,216
Unrealized hedging gains		$ 6,950

XML

7. Inventories (Tables)

9 Months Ended

Sep. 30, 2014

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of the following:

	September 30,		December 31,
	2014		2013
Oil-based mud blendstock	$	778,698	$	-
Naphtha		1,265,891		804,490
Atmospheric gas oil		536,900		575,919
Jet fuel		4,926,222		1,444,399
LPG mix		39,376		28,888
Crude		19,041		19,041
NRLM		-		1,813,662
	$	7,566,128	$	4,686,399

XML

13. Long-Term Debt (Details 1) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Cost	$ 537,130	$ 0
Less:  Accumulated depreciation	0	0
Capital lease obligation	$ 537,130	$ 0

XML

20. Fair Value Measurement

9 Months Ended

Sep. 30, 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 can execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity risks associated with our refined petroleum products and crude oil inventory and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil inputs. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreements 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 September 30, 2014 and December 31, 2013 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at September 30, 2014 and December 31, 2013 was $12,334,473 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 September 30, 2014 and the basis for that measurement:

				Fair Value Measurement at September 30, 2014 Using
Financial assets (liabilities):	Carrying Value at September 30, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(19,200	)	$	(19,200	)	$	-	$	-

			Fair Value Measurement at December 31, 2013 Using
Financial assets: (liabilities)	Carrying Value at December 31, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	6,950	$	6,950	$	-	$	-

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

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9. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Payables and Accruals [Abstract]
Expense for service	$ 2,496,514	$ 2,629,518	$ 8,092,738	$ 8,099,371
Accounts payable, related party	$ 1,801,376		$ 1,801,376		$ 3,659,340

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21. Refined Products Inventory Risk Management (Tables)

9 Months Ended

Sep. 30, 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):

Inventory positions (futures):	2014		2015		2016
Refined petroleum products and crude oil -
net short positions		45,000		-		-

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 September 30, 2014 and December 31, 2013: 

		Fair Value
		September 30,
Asset Derivatives	Balance Sheets Location	2014			2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	(19,200	)	$	6,950

Effect of derivative instruments

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013: 

		Gain (Loss) Recognized
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Derivatives	Statements of Operations Location	2014		2013			2014			2013
Commodity contracts	Cost of refined products sold	$	396,271	$	(297,179	)	$	(12,438	)	$	(330,320	)

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12. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

AROs on a roll-forward basis were as follows:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(2,912	)
Accretion expense		158,264
		2,053,993
Less:  current portion of asset retirement obligations		107,509
Asset retirement obligations, long-term balance
at September 30, 2014	$	1,946,484

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10. Note Payable (Details Narrative) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Note Payable Details Narrative
Sovereign principal amount outstanding	$ 1,795,702
Interest accrued on sovereign note	8,979
Short-Term Captial Leases		2,505
Financing services cost		$ 9,379

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts, USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Commodity Contracts
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ (19,200)		$ (19,200)		$ 6,950
Cost of refined products sold	$ 396,271	$ (297,179)	$ (12,438)	$ (330,320)

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17. Leases (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Leases Details Narrative
Rent expense	$ 26,129	$ 25,161	$ 77,787	$ 76,382

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6. Deposits (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Deposits Details
Utility deposits	$ 10,250	$ 10,250
Equipment deposits	48,785	124,526
Tax bonds	792,000	792,000
Purchase option deposits		283,421
Rent deposits	9,463	9,463
Deposits	$ 860,498	$ 1,219,660

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4. Business Segment Information

9 Months Ended

Sep. 30, 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 U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.

Segment financials for the three months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Three Months Ended September 30, 2014
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	87,846,757		$	56,900		$	-		$	87,903,657
Operation cost(1)(2)(3)		(86,355,916	)		(110,872	)		(274,674	)		(86,741,462	)
Other non-interest income		282,516			-			-			282,516
EBITDA	$	1,773,357		$	(53,972	)	$	(274,674	)
Depletion, depreciation and amortization											(393,871	)
Interest expense, net											(212,594	)
Income before income taxes										$	838,246
Capital expenditures	$	815,849		$	-		$	-		$	815,849
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $466,821 and an unrealized loss of $70,550.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the three months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Three Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	106,541,284		$	79,109		$	-		$	106,620,393
Less:  Operation cost(1)(2)(3)		(107,961,900	)		(114,105	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			278,349
EBITDA	$	(1,142,267	)	$	(34,996	)	$	(340,612	)
Depletion, depreciation and amortization											(337,156	)
Interest expense, net											(225,706	)
Loss before income taxes										$	(2,080,737	)
Capital expenditures	$	356,889		$	-		$	-		$	356,889
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the nine months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Nine Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	310,938,981		$	178,793		$	-		$	311,117,774
Operation cost(1)(2)(3)		(300,291,370	)		(355,645	)		(973,154	)		(301,620,169	)
Other non-interest income		847,549			208,333			-			1,055,882
EBITDA	$	11,495,160		$	31,481		$	(973,154	)
Depletion, depreciation and amortization											(1,175,643	)
Interest expense, net											(630,175	)
Income before income taxes										$	8,747,669
Capital expenditures	$	1,145,720		$	-		$	-		$	1,145,720
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $13,712 and an unrealized loss of $26,150.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the nine months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Nine Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	320,025,559		$	229,362		$	-		$	320,254,921
Operation cost(1)(2)(3)		(325,625,984	)		(433,065	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			835,048
EBITDA	$	(4,765,377	)	$	(203,703	)	$	(1,198,664	)
Depletion, depreciation and amortization											(997,671	)
Interest expense, net											(785,663	)
Loss before income taxes										$	(7,951,078	)
Capital expenditures	$	1,244,859		$	-		$	-		$	1,244,859
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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18. Income Taxes (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Taxes Details Narrative
Income tax expense	$ 22,199		$ 298,792
Accrued Texas margins tax	146,033		146,033
Amount of NOLs	18,800,000		18,800,000
Utilized amount of NOLs	1,900,000		1,900,000
Post-merger NOLs	$ 5,700,000		$ 5,700,000

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1. Organization (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Organization Details
Cash and cash equivalents	$ 1,182,475	$ 434,717	$ 314,812	$ 420,896

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3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Use of Estimates

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

Cash equivalents include 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, exceed insured 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 $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted Cash

Restricted cash was $1,005,886 and $327,388 at September 30, 2014 and December 31, 2013, respectively. These amounts include a payment reserve account to be drawn upon by AFNB in the event that we fail to timely make any payment as required under the Loan Agreement.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured cash balances of $1,409,238 and $77,388 at September 30, 2014 and December 31, 2013, respectively.

For the three months ended September 30, 2014, we had 3 customers that accounted for approximately 71% of our refined petroleum product sales.  These 3 customers represented approximately $6.4 million in accounts receivable at September 30, 2014.  For the three months ended September 30, 2013, we had 4 customers that accounted for approximately 91% of our refined petroleum product sales.  These 4 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

For the nine months ended September 30, 2014, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales.  These 4 customers represented approximately $7.7 million in accounts receivable at September 30, 2014.  For the nine months ended September 30, 2013, we had 5 customers that accounted for approximately 92% of our refined petroleum product sales.  These 5 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

Inventory

Inventory

Our inventory primarily consists of refined petroleum products.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.

Price-Risk Management Activities

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory 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.

Property and Equipment

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 in 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 three and nine months ended September 30, 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 U.S. Gulf of Mexico oil and gas properties had no production during the three and nine months ended September 30, 2014 and 2013.  All leases associated with our U.S. 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.

Intangibles - Other

Intangibles – Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with 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 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

Debt Issue Costs

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 $473,186 and $498,536 at September 30, 2014 and December 31, 2013, respectively.  Accumulated amortization was $202,794 and $177,445 at September 30, 2014 and December 31, 2013, respectively.

Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 2014.  Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 2013.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil. Revenue from refined product 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 in cash and in the form of a cash-backed security bond 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 in the form of a cash-backed security bond 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 bond secures.

Tank Storage Rental and Easement Revenue. Tank storage 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

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.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

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.

In assessing 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.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (18) Income Taxes” of this report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

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

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.

Derivatives

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical 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 products sold in our consolidated statements of operations using mark-to-market accounting.

Computation of Earnings Per Share

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 unaudited 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.

Stock Based Compensation

Stock-Based Compensation

In accordance with FASB ASC guidance for stock-based compensation, share-based payments to employees, 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).

Treasury Stock

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.

Business Combinations

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

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

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.

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23. Subsequent Events

9 Months Ended

Sep. 30, 2014

Subsequent Events [Abstract]

Subsequent Events

Master Easement Agreement - BDPL and FLNG

On October 30, 2014, FLNG made a second payment of $250,000 to BDPL. Such 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.  See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to the Master Easement Agreement.

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13. Long-Term Debt (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery Loan	$ 8,755,089	$ 9,057,937
Notre Dame Debt	1,300,000	1,300,000
Capital leases	483,682
Construction and Funding Agreement		5,747,330
Total	10,538,771	16,105,267
Less: Current portion of long-term debt	590,098	2,215,918
Long term debt	$ 9,948,673	$ 13,889,349

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3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Cash and cash equivalents	$ 1,182,475	$ 314,812	$ 1,182,475	$ 314,812	$ 434,717	$ 420,896
Restricted cash	1,005,886		1,005,886		327,388
Perecentage of revenue from major customers		91.00%	84.00%	92.00%
Perecentage of revenue from Three major customers	71.00%
Three major customers accounts recievable	6,400,000		6,400,000
Four major customers accounts recievable	7,700,000	6,500,000	7,700,000	6,500,000
Five majory customer accounts receivable		6,500,000		6,500,000
Accumulated amortization	202,794		202,794		177,445
Uninsured balances	1,409,238		1,409,238		77,388
Amortization expense	8,450	8,450	25,350	25,350
Debt issuance costs	$ 473,186		$ 473,186		$ 498,536

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4. Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Business segment reporting

Segment financials for the three months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Three Months Ended September 30, 2014
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	87,846,757		$	56,900		$	-		$	87,903,657
Operation cost(1)(2)(3)		(86,355,916	)		(110,872	)		(274,674	)		(86,741,462	)
Other non-interest income		282,516			-			-			282,516
EBITDA	$	1,773,357		$	(53,972	)	$	(274,674	)
Depletion, depreciation and amortization											(393,871	)
Interest expense, net											(212,594	)
Income before income taxes										$	838,246
Capital expenditures	$	815,849		$	-		$	-		$	815,849
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $466,821 and an unrealized loss of $70,550.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the three months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Three Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	106,541,284		$	79,109		$	-		$	106,620,393
Less:  Operation cost(1)(2)(3)		(107,961,900	)		(114,105	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			278,349
EBITDA	$	(1,142,267	)	$	(34,996	)	$	(340,612	)
Depletion, depreciation and amortization											(337,156	)
Interest expense, net											(225,706	)
Loss before income taxes										$	(2,080,737	)
Capital expenditures	$	356,889		$	-		$	-		$	356,889
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the nine months ended September 30, 2014 (and at September 30, 2014) were as follows:

	Nine Months Ended September 30, 2014
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	310,938,981		$	178,793		$	-		$	311,117,774
Operation cost(1)(2)(3)		(300,291,370	)		(355,645	)		(973,154	)		(301,620,169	)
Other non-interest income		847,549			208,333			-			1,055,882
EBITDA	$	11,495,160		$	31,481		$	(973,154	)
Depletion, depreciation and amortization											(1,175,643	)
Interest expense, net											(630,175	)
Income before income taxes										$	8,747,669
Capital expenditures	$	1,145,720		$	-		$	-		$	1,145,720
Identifiable assets(4)	$	57,520,835		$	2,998,619		$	523,533		$	61,042,987

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory. Cost of refined products sold within operation cost includes a realized gain of $13,712 and an unrealized loss of $26,150.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

Segment financials for the nine months ended September 30, 2013 (and at September 30, 2013) were as follows:

	Nine Months Ended September 30, 2013
	Segment
	Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total
Revenues	$	320,025,559		$	229,362		$	-		$	320,254,921
Operation cost(1)(2)(3)		(325,625,984	)		(433,065	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			835,048
EBITDA	$	(4,765,377	)	$	(203,703	)	$	(1,198,664	)
Depletion, depreciation and amortization											(997,671	)
Interest expense, net											(785,663	)
Loss before income taxes										$	(7,951,078	)
Capital expenditures	$	1,244,859		$	-		$	-		$	1,244,859
Identifiable assets(4)	$	48,925,380		$	1,569,005		$	844,334		$	51,338,719

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory.  Cost of refined products sold within operation cost includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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5. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2014

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid expenses and other current assets consisted of the following:

	September 30,		December 31,
	2014		2013
Prepaid insurance	$	73,278	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		3,750		15,000
Prepaid taxes		-		9,216
Unrealized hedging gains		-		6,950
	$	181,028	$	333,683

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3. Significant Accounting Policies

9 Months Ended

Sep. 30, 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 generally accepted accounting principles 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 equivalents include 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, exceed insured 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 $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted cash was $1,005,886 and $327,388 at September 30, 2014 and December 31, 2013, respectively. These amounts include a payment reserve account to be drawn upon by AFNB in the event that we fail to make any payment in timely manner as required under the Loan Agreement.

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

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured cash balances of $1,409,238 and $77,388 at September 30, 2014 and December 31, 2013, respectively.

For the three months ended September 30, 2014, we had 3 customers that accounted for approximately 71% of our refined petroleum product sales.  These 3 customers represented approximately $6.4 million in accounts receivable at September 30, 2014.  For the three months ended September 30, 2013, we had 4 customers that accounted for approximately 91% of our refined petroleum product sales.  These 4 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

For the nine months ended September 30, 2014, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales.  These 4 customers represented approximately $7.7 million in accounts receivable at September 30, 2014.  For the nine months ended September 30, 2013, we had 5 customers that accounted for approximately 92% of our refined petroleum product sales.  These 5 customers represented approximately $6.5 million in accounts receivable at September 30, 2013.

Inventory

Our inventory primarily consists of refined petroleum products.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory 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.

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 in 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 three and nine months ended September 30, 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 U.S. Gulf of Mexico oil and gas properties had no production during the three and nine months ended September 30, 2014 and 2013.  All leases associated with our U.S. 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.

Intangibles – Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with 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 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

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 $473,186 and $498,536 at September 30, 2014 and December 31, 2013, respectively.  Accumulated amortization was $202,794 and $177,445 at September 30, 2014 and December 31, 2013, respectively.

Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 2014.  Amortization expense, which is included in interest expense, was $8,450 and $25,350 for the three and nine months ended September 30, 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 product 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 in cash and in the form of a cash-backed security bond 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 in the form of a cash-backed security bond 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 bond secures.

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.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

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.

In assessing 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.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  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.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical 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 products sold in our consolidated statements of operations using mark-to-market accounting.

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 unaudited 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.

Stock-Based Compensation

In accordance with FASB ASC guidance for stock-based compensation, share-based payments to employees, 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).

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.

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.

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6. Deposits (Tables)

9 Months Ended

Sep. 30, 2014

Deposits Tables

Deposit balances

Deposits consisted of the following:

	September 30,		December 31,
	2014		2013
Utility deposits	$	10,250	$	10,250
Equipment deposits		48,785		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	860,498	$	1,219,660

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19. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings per share

The following table provides reconciliation between basic and diluted income (loss) per share:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Net income (loss)	$	816,047	$	(2,080,737	)	$	8,448,877	$	(7,951,078	)
Basic and diluted income (loss) per share	$	0.08	$	(0.20	)	$	0.81	$	(0.76	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,446,218		10,421,731			10,439,684		10,450,906

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11. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Accrued Expenses And Other Current Liabilities Details
Excise and income taxes payable	$ 1,080,413	$ 688,754
Genesis crude accrued payable	384,362
Transportation and inspection	40,000	100,000
Property taxes	30,109
Unrealized hedging loss	19,200
Unearned revenue	94,172	302,505
Board of director fees payable	341,250	240,000
Other payable	188,918	269,185
Accrued Expenses and Other Current Liabilities, Net	$ 2,178,424	$ 1,600,444

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2014	Dec. 31, 2013
CURRENT ASSETS
Cash and cash equivalents	$ 1,182,475	$ 434,717
Restricted cash	1,005,886	327,388
Accounts receivable	11,428,482	13,487,106
Prepaid expenses and other current assets	181,028	333,683
Deposits	860,498	1,219,660
Inventory	7,566,128	4,686,399
Total current assets	22,224,497	20,488,953
Total property and equipment, net	37,191,958	36,388,666
Surety bonds	850,000
Debt issue costs, net	473,186	498,536
Trade name	303,346	303,346
TOTAL ASSETS	61,042,987	57,679,501
CURRENT LIABILITIES
Accounts payable	20,030,921	20,783,541
Accounts payable, related party	1,801,376	3,659,340
Notes payable	1,795,702	11,884
Asset retirement obligations, current portion	107,509	107,388
Accrued expenses and other current liabilities	2,178,424	1,600,444
Interest payable, current portion	49,106	40,272
Long-term debt, current portion	590,098	2,215,918
Total current liabilities	26,553,136	28,418,787
Long-term liabilities:
Asset retirement obligations, net of current portion	1,946,484	1,490,273
Deferred revenues and expenses	734,745
Long-term debt, net of current portion	9,948,673	13,889,349
Long-term interest payable, net of current portion	1,222,360	1,767,381
Total long-term liabilities	13,852,262	17,147,003
TOTAL LIABILITIES	40,405,398	45,565,790
Commitments and contingencies
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized;10,596,218 and 10,580,973 shares issued at September 30, 2014 and December 31, 2013, respectively)	105,963	105,810
Additional paid-in capital	36,698,813	36,623,965
Accumulated deficit	(15,367,187)	(23,816,064)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	20,637,589	12,113,711
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 61,042,987	$ 57,679,501

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4. Business Segment Information (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues	$ 87,903,657	$ 106,620,393	$ 311,117,774	$ 320,254,921
Refinery Operations [Member]
Revenues	87,846,757	106,541,284	310,938,981	320,025,559
Operation cost	(86,355,916)	(107,961,900)	(300,291,370)	(325,625,984)
Other non-interest income	282,516	278,349	847,549	835,048
EBITDA	1,773,357	(1,142,267)	11,495,160	(4,765,377)
Capital expenditures	815,849	356,889	1,145,720	1,244,859
Identifiable assets	57,520,835	48,925,380	57,520,835	48,925,380
Segment Pipeline Transportation [Member]
Revenues	56,900	79,109	178,793	229,362
Operation cost	(110,872)	(114,105)	(355,645)	(433,065)
Other non-interest income			208,333
EBITDA	(53,972)	(34,996)	31,481	(203,703)
Capital expenditures
Identifiable assets	2,998,619	1,569,005	2,998,619	1,569,005
Corporate and Other [Member]
Revenues
Operation cost	(274,674)	(340,612)	(973,154)	(1,198,664)
Other non-interest income
EBITDA	(274,674)	(340,612)	(973,154)	(1,198,664)
Capital expenditures
Identifiable assets	523,533	844,334	523,533	844,334
Total
Revenues	87,903,657	106,620,393	311,117,774	320,254,921
Operation cost	(86,741,462)	(108,416,617)	(301,620,169)	(327,257,713)
Other non-interest income	282,516	278,349	1,055,882	835,048
Depletion, depreciation and amortization	(393,871)	(337,156)	(1,175,643)	(997,671)
Interest expense, net	(212,594)	(225,706)	(630,175)	(785,663)
Income before income taxes	838,246	(2,080,737)	8,747,669	(7,951,078)
Capital expenditures	815,849	356,889	1,145,720	1,244,859
Identifiable assets	$ 61,042,987	$ 51,338,719	$ 61,042,987	$ 51,338,719

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1. Organization

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Nature of Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company.  We are primarily an independent refiner and marketer of petroleum products.  Our primary operating asset is a 56-acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  Operations at the Nixon Facility also involve the storage and terminaling of petroleum under third-party lease agreements. 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.

We conduct substantially all of our operations through our wholly-owned subsidiaries. Our operating subsidiaries include:

●   Lazarus Energy, LLC, a Delaware limited liability company (petroleum processing assets) (“LE”);

●   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).

Operating Risks

We had cash and cash equivalents of $1,182,475 and $434,717 at September 30, 2014 and December 31, 2013, respectively.  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 $10,000,000 (the “Refinery Note”).  In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”).  We are currently making our scheduled payments in accordance with the terms and conditions of the Loan Agreement.  As of December 31, 2013, we were in violation of the current ratio covenant in the Loan Agreement. Effective December 31, 2013, AFNB agreed to waive certain financial maintenance covenants (the “Waiver Agreement”) relating to debt-to-worth and current ratio (the “Financial Maintenance Covenants”) under the Loan Agreement.  As of September 30, 2014 and the date of filing of this report, we were in compliance with the Financial Maintenance Covenants.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

We currently rely on our profit share under the Joint Marketing Agreement dated August 12, 2011 (the “Joint Marketing Agreement”) by and between LE and GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LLC (“Genesis”) and Lazarus Energy Holdings, LLC (“LEH”), our controlling shareholder, to fund our working capital requirements.  GEL is also the exclusive supplier of our crude oil for the Nixon Facility under the Crude Oil and Supply Throughput Services Agreement by and between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”).  During months in which we receive no profit share under the Joint Marketing Agreement, GEL and/or LEH may, but are not required to, fund our working capital requirements. There can be no assurances that either GEL or LEH will continue to fund our working capital requirements.  In the event our working capital requirements are not funded by either our profit share, GEL or LEH, then we may experience a significant and material adverse effect on our operating results.  See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to the end of term for the Joint Marketing Agreement and Crude Supply Agreement.

We believe that our operational strategy, including: (i) increased production of and expansion of our customer base for jet fuel, and (ii) continued refurbishment of key components of the Nixon Facility, including the naphtha stabilizer and depropanizer units will be sufficient to support our operations over the next twelve months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve its anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share, GEL, or LEH, then we may experience a significant and material adverse effect on our operating results, liquidity, and financial condition.

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15. Treasury Stock (Details Narrative)	Sep. 30, 2014	Dec. 31, 2013
Treasury Stock Details Narrative
Treasury stock	150,000	150,000

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10. Note Payable (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Notes payable

Notes payable consisted of the following:

	September 30,		December 31,
	2014		2013
Short-Term Notes	$	1,795,702	$	9,379
Short-Term Captial Leases		-		2,505
	$	1,795,702	$	11,884

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20. Fair Value Measurement (Details Narrative) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Fair Value Measurement Details Narrative
Fair value of long term debt and short-term notes payable	$ 12,334,473	$ 16,117,152

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17. Leases

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Leases

We are currently under a ten-year lease agreement expiring in 2017 for office space in downtown Houston, Texas, which serves as our company headquarters.  We are committed to pay a portion of the related actual operating expenses under the lease agreement, which includes free rent periods or escalating rent payment provisions.  We recognize rent expense under such arrangements on a straight-line basis. For the three months ended September 30, 2014 and 2013, rent expense for the office lease was $26,129 and $25,161, respectively. For the nine months ended September 30, 2014 and 2013, rent expense for the office lease was $77,787 and $ 76,382, respectively.

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11. Accrued Expenses and Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2014

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consisted of the following: 

	September 30,		December 31,
	2014		2013
Excise and income taxes payable	$	1,080,413	$	688,754
Genesis crude accrued payable		384,362		-
Transportation and inspection		40,000		100,000
Property taxes		30,109		-
Unrealized hedging loss		19,200		-
Unearned revenue		94,172		302,505
Board of Director fees payable		341,250		240,000
Other payable		188,918		269,185
	$	2,178,424	$	1,600,444

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19. Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

The following table provides reconciliation between basic and diluted income (loss) per share:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Net income (loss)	$	816,047	$	(2,080,737	)	$	8,448,877	$	(7,951,078	)
Basic and diluted income (loss) per share	$	0.08	$	(0.20	)	$	0.81	$	(0.76	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,446,218		10,421,731			10,439,684		10,450,906

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 three and nine months ended September 30, 2014 is the same as there were no stock options or other dilutive instruments outstanding.  Diluted EPS for the three and nine months ended September 30, 2013 excludes stock options outstanding as they would be anti-dilutive.

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22. Commitments and Contingencies (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Commitments And Contingencies Details
Construction and Funding Agreement		$ 5,747,330

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2. Basis of Presentation

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Basis of Presentation

We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. 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.  This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Sep. 30, 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	10,596,218	10,580,973
Common stock, shares outstanding	10,596,218	10,580,973
Treasury stock, shares	150,000	150,000

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12. Asset Retirement Obligations

9 Months Ended

Sep. 30, 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.

AROs on a roll-forward basis were as follows:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(2,912	)
Accretion expense		158,264
		2,053,993
Less:  current portion of asset retirement obligations		107,509
Asset retirement obligations, long-term balance
at September 30, 2014	$	1,946,484

On February 5, 2014, WBI and BDPL entered into the 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 $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. Once plugging and abandonment work has been completed, the collateral will be released to BDPL.  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 the pipelines.

For the three months ended September 30, 2014 and 2013, we recognized $0 and $8, respectively, in abandonment expense related to our oil and gas properties.  For the nine months ended September 30, 2014 and 2013, we recognized $0 and $51,360, respectively, in abandonment expense related to our oil and gas properties.  AROs for 2013 were associated with our High Island A7 and High Island 37 oil and gas properties. We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 14, 2014
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,446,218
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2014

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13. Long-Term Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Long-Term Debt

Long-term debt consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery Note	$	8,755,089	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		483,682		-
Construction and Funding Agreement		-		5,747,330
		10,538,771		16,105,267
Less: Current portion of long-term debt		590,098		2,215,918
	$	9,948,673	$	13,889,349

Refinery Note.   The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at September 30, 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 $8,755,089 and $9,057,937 at September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Refinery Note in the amount of $40,127 and $40,132 at September 30, 2014 and December 31, 2013, respectively.  See “Note (1) Organization – Operating Risks” of this report for additional disclosures related to the Refinery Note.

The Loan Agreement has Financial Maintenance Covenants.  As of December 31, 2013, we were in violation of the current ratio covenant in the Loan Agreement. However, the Waiver Agreement waives any default or event of default that may have occurred in relation to LE’s non-compliance with the Financial Maintenance Covenants and is effective through December 31, 2014. As of September 30, 2014 and the date of filing of this report, we were in compliance with the Financial Maintenance Covenants.  Accordingly, the Refinery Note has been classified as long-term on our consolidated balance sheets.

In October 2011, the Refinery Loan Documents were acquired by AFNB.  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.

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 September 30, 2014 and December 31, 2013.  Interest was accrued on the Notre Dame Debt in the amount of $1,222,360 and $1,066,784 at September 30, 2014 and December 31, 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 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/

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.

Capital Leases.  Long-term capital lease obligations totaled $483,682 and $0 at September 30, 2014 and December 31, 2013. The following is a summary of equipment held under long-term capital leases:

	September 30,		December 31,
	2014		2013
Cost	$	537,130	$	-
Less:  Accumulated depreciation		-		-
	$	537,130	$	-

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 is estimated to be completed and delivered in December 2014. The long-term capital lease obligation requires a monthly payment of $14,332 per month. However, until the equipment is delivered, we are required to make payments of $7,159 per month.

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.  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 September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Construction and Funding Agreement in the amount of $0 and $700,597 at September 30, 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 shall now receive up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement.  In addition, Milam shall release all liens on the Nixon Facility.  See “Part I, Item 1. Financial Statements - Note (22) Commitments and Contingencies” of this report for additional disclosures related to the Construction and Funding Agreement and our relationship with Genesis.

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
REVENUE FROM OPERATIONS
Refined product sales	$ 87,846,757	$ 106,541,284	$ 310,938,981	$ 320,025,559
Pipeline operations	56,900	78,909	178,793	229,162
Oil and gas sales		200		200
Total revenue from operations	87,903,657	106,620,393	311,117,774	320,254,921
COST OF OPERATIONS
Cost of refined products sold	83,876,239	105,314,208	292,154,207	317,508,586
Refinery operating expenses	2,496,514	2,629,518	8,092,738	8,099,371
Pipeline operating expenses	50,100	40,813	139,542	122,592
Lease operating expenses	7,041	16,797	21,037	58,088
General and administrative expenses	253,437	387,100	1,049,981	1,333,203
Depletion, depreciation and amortization	393,871	337,156	1,175,643	997,671
Abandonment expense		8		51,360
Accretion expense	53,731	28,173	158,264	84,513
Total cost of operations	87,130,933	108,753,773	302,791,412	328,255,384
Income (loss) from operations	772,724	(2,133,380)	8,326,362	(8,000,463)
OTHER INCOME (EXPENSE)
Tank rental and easement revenue	282,516	278,349	1,055,882	835,048
Interest and other income	1,813	668	45,411	2,480
Interest expense	(214,407)	(226,374)	(675,586)	(788,143)
Loss on disposal of property and equipment	(4,400)		(4,400)
Total other income	65,522	52,643	421,307	49,385
Income (loss) before income taxes	838,246	(2,080,737)	8,747,669	(7,951,078)
Income tax expense, current	(22,199)		(298,792)
Net income (loss)	$ 816,047	$ (2,080,737)	$ 8,448,877	$ (7,951,078)
Income (loss) per common share
Basic	$ 0.08	$ (0.20)	$ 0.81	$ (0.76)
Diluted	$ 0.08	$ (0.20)	$ 0.81	$ (0.76)
Weighted average number of common shares outstanding:
Basic	10,446,218	10,421,731	10,439,684	10,450,906
Diluted	10,446,218	10,421,731	10,439,684	10,450,906

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7. Inventory

9 Months Ended

Sep. 30, 2014

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of the following:

	September 30,		December 31,
	2014		2013
Oil-based mud blendstock	$	778,698	$	-
Naphtha		1,265,891		804,490
Atmospheric gas oil		536,900		575,919
Jet fuel		4,926,222		1,444,399
LPG mix		39,376		28,888
Crude		19,041		19,041
NRLM		-		1,813,662
	$	7,566,128	$	4,686,399

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6. Deposits

9 Months Ended

Sep. 30, 2014

Banking and Thrift [Abstract]

Deposits

Deposits consisted of the following:

	September 30,		December 31,
	2014		2013
Utility deposits	$	10,250	$	10,250
Equipment deposits		48,785		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	860,498	$	1,219,660

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18. Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

LE is a limited liability company and, prior to our reverse merger with LE on February 15, 2012, LE’s taxable income or net operating losses (“NOLs”) flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. As a result of the reverse merger, LE became a subsidiary of Blue Dolphin and LE’s taxable income or loss flowed through to Blue Dolphin for federal and state income tax purposes.

Section 382 of the Internal Revenue Code imposes a limitation on the use of Blue Dolphin’s NOLs generated prior to the reverse merger.  The amount of NOLs subject to such limitation is approximately $18.8 million, of which approximately $1.9 million is projected to be utilized for the nine months ended September 30, 2014.  NOLs generated subsequent to the reverse merger through December 31, 2013 of approximately $14.9 million are not subject to any such limitation. Approximately $5.7 million of the post-merger NOLs are projected to be utilized for the nine months ended September 30, 2014.  As of September 30, 2014 and December 31, 2013, our deferred tax assets were fully reserved against due to the uncertainty of their use as a result of net losses prior to 2014.

For the three months ended September 30, 2014 and 2013, income tax expense was $22,199 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $1,395 was the result of alternative minimum tax.

For the nine months ended September 30, 2014 and 2013, income tax expense was $298,792 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $152,795 was the result of alternative minimum tax.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.  At September 30, 2014, we accrued $146,033 in TMT.

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14. Stock Options

9 Months Ended

Sep. 30, 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 merger with LE, all employees of Blue Dolphin became employees of LEH effective February 15, 2012.  Therefore, all options outstanding for Blue Dolphin employees were cancelled 90 days following the effective date of the reverse merger.  At September 30, 2014, there were no options outstanding, no options exercisable or no shares of common stock reserved for issuance under the 2000 Stock Incentive Plan.

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10. Note Payable

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Note Payable

Notes payable consisted of the following:

	September 30,		December 31,
	2014		2013
Short-Term Notes	$	1,795,702	$	9,379
Short-Term Captial Leases		-		2,505
	$	1,795,702	$	11,884

Short-Term Notes.  On May 2, 2014, LRM entered into a loan and security agreement with Sovereign Bank, a Texas state bank, for a term loan facility in the aggregate amount of $2.0 million (the “Sovereign Note”).  The proceeds of the Sovereign Note are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units.  The Sovereign Note is due in May 2015 and bears interest at 6.00%.  The Sovereign Note 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 Note was $1,795,702 and $0 at September 30, 2014 and December 31, 2013, respectively.  Interest was accrued on the Sovereign Note in the amount of $8,979 and $0 at September 30, 2014 and December 31, 2013, respectively.

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 September 30, 2014 and December 31, 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 September 30, 2014 and December 31, 2013, respectively.  These capital leases were paid off during the first quarter of 2014.

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16. Concentration of Risk (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Concentration Risk	0.20%	0.00%		0.00%
Naphtha
Concentration Risk	21.80%	24.30%	23.00%	25.60%
Jet Fuel
Concentration Risk	29.60%	4.80%	23.30%	1.60%
NRLM
Concentration Risk	0.00%	44.90%	15.80%	48.20%
Oil-based mud blendstock
Concentration Risk	25.10%	0.00%	12.70%	0.00%
Atmospheric gas oil
Concentration Risk	23.30%	26.00%	25.00%	24.50%
Reduced crude
Concentration Risk	0.00%	0.00%	0.00%	0.10%

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8. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property, plant and equipment, net, consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery and facilities	$	36,209,053	$	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
		39,861,697		39,150,367
Less:  Accumulated depletion, depreciation and amortization		4,191,256		3,016,713
		35,670,441		36,133,654
Construction in Progress		1,521,517		255,012
Property, Plant and Equipment, Net	$	37,191,958	$	36,388,666

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9. Accounts Payable, Related Party

9 Months Ended

Sep. 30, 2014

Payables and Accruals [Abstract]

Accounts Payable, Related Party

LEH, our controlling shareholder, owns approximately 81% of our outstanding common stock, par value $0.01 per share (the “Common Stock”).  Jonathan Carroll, Chairman of the Board of Directors (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 a Management Agreement dated February 15, 2012.  On May 12, 2014, the Management Agreement was amended by: (i) extending the term to August 12, 2015, and (ii) changing the name of the agreement from “Management Agreement” to “Operating Agreement” (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 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 three months ended September 30, 2014 and 2013 were $2,496,514 (approximately $2.94 per barrel of throughput) and $2,629,518 (approximately $2.68 per barrel of throughput), respectively.  Aggregate amounts expensed for Services at the Nixon Facility for the nine months ended September 30, 2014 and 2013 were $8,092,738 (approximately $2.78 per barrel of throughput) and $8,099,371 (approximately $2.73 per barrel of throughput).

At September 30, 2014 and December 31, 2013, the amounts outstanding to LEH to fund our working capital requirements were $1,801,376 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.

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11. Accrued Expenses and Other Current Liabilities

9 Months Ended

Sep. 30, 2014

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following: 

	September 30,		December 31,
	2014		2013
Excise and income taxes payable	$	1,080,413	$	688,754
Genesis crude accrued payable		384,362		-
Transportation and inspection		40,000		100,000
Property taxes		30,109		-

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20. Fair Value Measurement (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Financial assets (liabilties):
Commodity contracts	$ (19,200)	$ 6,950
FairValueInputsLevel1Member
Financial assets (liabilties):
Commodity contracts	(19,200)	6,950
FairValueInputsLevel2Member
Financial assets (liabilties):
Commodity contracts	0	0
FairValueInputsLevel3Member
Financial assets (liabilties):
Commodity contracts	$ 0	$ 0

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Sep. 30, 2014
Refined products - net short (long) positions
Volume in Thousands of barrels
Notional Contract Volumes 2014	45,000
Notional Contract Volumes 2015	0
Notional Contract Volumes 2016	0

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19. Earnings per share (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Net income (loss)	$ 816,047	$ (2,080,737)	$ 8,448,877	$ (7,951,078)
Basic and diluted earnings (loss) per common share
Basic and diluted income (loss) per share	$ 0.08	$ (0.20)	$ 0.81	$ (0.76)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,446,218	10,421,731	10,439,684	10,450,906

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8. Property, Plant and Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property and equipment

Property, plant and equipment, net, consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery and facilities	$	36,209,053	$	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
		39,861,697		39,150,367
Less:  Accumulated depletion, depreciation and amortization		4,191,256		3,016,713
		35,670,441		36,133,654
Construction in Progress		1,521,517		255,012
Property, Plant and Equipment, Net	$	37,191,958	$	36,388,666

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10. Note Payable (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Short-Term Note	$ 1,795,702	$ 9,379
Short-Term Captial Leases		2,505
Note Payable,Total	$ 1,795,702	$ 11,884

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16. Concentration of Risk

9 Months Ended

Sep. 30, 2014

Risks and Uncertainties [Abstract]

Concentration of Risk

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 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 (2) Basis of Presentation” of this report for additional disclosures related to significant customers.

Sales by Product. All of our refined petroleum products are currently sold in the United States. The following table summarizes the percentages of all refined petroleum products sales to total sales:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
LPG mix		0.2	%		0.0	%		0.2	%		0.0	%
Naphtha		21.8	%		24.3	%		23.0	%		25.6	%
Jet fuel		29.6	%		4.8	%		23.3	%		1.6	%
NRLM		0.0	%		44.9	%		15.8	%		48.2	%
Oil-based mud blendstock		25.1	%		0.0	%		12.7	%		0.0	%
Atmospheric gas oil		23.3	%		26.0	%		25.0	%		24.5	%
Reduced crude		0.0	%		0.0	%		0.0	%		0.1	%
		100.0	%		100.0	%		100.0	%		100.0	%

On May 31, 2014, the Nixon Facility discontinued production of Non-Road, Locomotive and Marine diesel (“NRLM,” also commonly referred to as low-sulfur diesel).  On June 1, 2014, the Nixon Facility began producing oil-based mud blendstock, a non-fuel petroleum product.  The shift in product slate from NRLM to oil-based mud blendstock was the result of an Environmental Protection Agency (“EPA”) mandate originally instituted in June 2004 and amended in December 2009 that required a reduction in the sulfur content found in all transportation related diesel fuels. Specific provisions of the EPA standards, as revised, required NRLM produced by small refiners to meet a maximum specification of 15 parts per million of sulfur by June 1, 2014.  The Nixon Facility is currently not equipped to produce transportation related products at the EPA’s lower sulfur content standard.

The Nixon Facility began producing jet fuel in mid-September 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.

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement.  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.

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products and Crude Oil Inventory Risk Management

Under our refined petroleum products and crude oil inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations in our inventory. The physical 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 and crude oil 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 September 30, 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):

Inventory positions (futures):	2014		2015		2016
Refined petroleum products and crude oil -
net short positions		45,000		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at September 30, 2014 and December 31, 2013: 

		Fair Value
		September 30,
Asset Derivatives	Balance Sheets Location	2014			2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	(19,200	)	$	6,950

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013: 

		Gain (Loss) Recognized
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
Derivatives	Statements of Operations Location	2014		2013			2014			2013
Commodity contracts	Cost of refined products sold	$	396,271	$	(297,179	)	$	(12,438	)	$	(330,320	)

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8. Property, Plant and Equipment, Net (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Property Plant And Equipment Net Details
Refinery and facilities	$ 36,209,053	$ 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	39,861,697	39,150,367
Less: Accumulated depletion, depreciation and amortization	4,191,256	3,016,713
Property, Plant and Equipment less depreciation	35,670,441	36,133,654
Construction in Progress	1,521,517	255,012
Property, Plant and Equipment, Net	$ 37,191,958	$ 36,388,666

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20. Fair Value Measurement (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2014 and the basis for that measurement:

				Fair Value Measurement at September 30, 2014 Using
Financial assets (liabilities):	Carrying Value at September 30, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(19,200	)	$	(19,200	)	$	-	$	-

			Fair Value Measurement at December 31, 2013 Using
Financial assets (liabilities):	Carrying Value at December 31, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	6,950	$	6,950	$	-	$	-

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
OPERATING ACTIVITIES
Net income (loss)	$ 8,448,877	$ (7,951,078)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,175,643	997,671
Unrealized loss on derivatives	26,150	(297,020)
Amortization of debt issue costs	25,350	25,350
Amortization of intangible assets		9,463
Accretion expense	158,264	84,513
Abandonment costs incurred		51,360
Common stock issued for services	75,001	100,000
Loss on disposal of assets	4,400
Changes in operating assets and liabilities
Restricted cash	(678,498)	62,210
Accounts receivable	2,058,624	6,358,937
Prepaid expenses and other current assets	152,655	(186,467)
Deposits and other assets	(490,838)	(213)
Inventory	(2,879,729)	(2,085,969)
Accounts payable, accrued expenses and other liabilities	(5,144)	(3,395,086)
Accounts payable, related party	(1,857,964)	1,665,782
Net cash provided by (used in) operating activities	6,212,791	(4,560,547)
INVESTING ACTIVITIES
Capital expenditures	(1,145,720)	(1,244,859)
Proceeds from sale of assets		201,000
Net cash used in investing activities	(1,145,720)	(1,043,859)
FINANCING ACTIVITIES
Proceeds from issuance of debt		5,750,611
Payments on long-term debt	(6,103,131)	(60,876)
Proceeds from notes payable	2,000,000	15,032
Payments on notes payable	(216,182)	(206,445)
Net cash provided by (used in) financing activities	(4,319,313)	5,498,322
Net increase (decrease) in cash and cash equivalents	747,758	(106,084)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	434,717	420,896
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,182,475	314,812
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
Financing of capital expenditures via capital lease	536,635
Deferred revenue recognized	115,254
Accrued services payable converted to common stock		50,000
Interest paid	$ 1,211,773	$ 617,091

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5. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 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:

	September 30,		December 31,
	2014		2013
Prepaid insurance	$	73,278	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		3,750		15,000
Prepaid taxes		-		9,216
Unrealized hedging gains		-		6,950
	$	181,028	$	333,683

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13. Long-Term Debt (Details Narrative) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery Note	$ 8,755,089	$ 9,057,937
Refinery loan accrued interest	40,127	40,132
Notre Dame debt accrued interest	1,222,360	1,066,784
Construction and Funding Agreement		5,747,330
Construction funding accrued interest		700,597
Capital leases	483,682
Effective rate	5.50%
Notre Dame Debt	$ 1,300,000	$ 1,300,000

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22. Commitments and Contingencies

9 Months Ended

Sep. 30, 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 to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil 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 has 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) 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 will 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 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 September 30, 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

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

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 $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  The bond increased the collateral held by a surety company relating to supplemental pipeline bonds issued on behalf of BDPL to satisfy the bonding requirements of the Bureau of Ocean Energy Management.  These supplemental pipeline bonds are intended to secure the performance of BDPL’s plugging and abandonment obligations with respect to pipeline segments in federal waters of the U.S. Gulf of Mexico.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

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.

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13. Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Long Term Debt

Long-term debt consisted of the following:

	September 30,		December 31,
	2014		2013
Refinery Note	$	8,755,089	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		483,682		-
Construction and Funding Agreement		-		5,747,330
		10,538,771		16,105,267
Less: Current portion of long-term debt		590,098		2,215,918
	$	9,948,673	$	13,889,349

Schedule of summary of equipment held under long-term capital leases

The following is a summary of equipment held under long-term capital leases:

	September 30,		December 31,
	2014		2013
Cost	$	537,130	$	-
Less:  Accumulated depreciation		-		-
	$	537,130	$	-

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15. Treasury Stock

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Treasury Stock

In March, 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.  As of September 30, 2014 and December 31, 2013, we had 150,000 shares of treasury stock.