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, 2013

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 issued and outstanding as of November 14, 2013:  10,580,973

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

FORM 10-Q REPORT INDEX

		Page
PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	3
	Condensed Consolidated Balance Sheets (Unaudited)	3
	Condensed Consolidated Statements of Operations (Unaudited)	4
	Condensed Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Condensed Consolidated Financial Statements (Unaudited)	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	46
ITEM 4.	CONTROLS AND PROCEDURES	46
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	48
ITEM 1A.	RISK FACTORS	48
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	48
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	48
ITEM 4.	MINE SAFETY DISCLOSURES	48
ITEM 5.	OTHER INFORMATION	48
ITEM 6.	EXHIBITS	48
SIGNATURES		49

2

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	314,812		$	420,896
Restricted cash		27,383			89,593
Accounts receivable		8,239,818			15,398,755
Prepaid expenses and other current assets		414,781			228,314
Deposits		1,236,660			1,236,447
Inventory		4,386,661			2,300,692
Total current assets		14,620,115			19,674,697
Total property and equipment, net		35,908,273			35,862,085
Debt issue costs, net		506,985			532,335
Other assets		-			9,463
Trade name		303,346			303,346
TOTAL ASSETS	$	51,338,719		$	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	15,048,520		$	19,171,013
Accounts payable, related party		3,259,803			1,594,021
Notes payable		30,244			43,941
Asset retirement obligations, current portion		88,044			-
Accrued expenses and other current liabilities		1,044,151			725,238
Interest payable, current portion		655,832			640,352
Long-term debt, current portion		20,018,498			1,816,960
Total current liabilities		40,145,092			23,991,525
Long-term liabilities:
Asset retirement obligations, net of current portion		909,486			921,260
Long-term debt, net of current portion		1,300,000			13,989,517
Long-term interest payable, net of current portion		1,014,356			858,784
Total long-term liabilities		3,223,842			15,769,561
TOTAL LIABILITIES		43,368,934			39,761,086
Commitments and contingencies
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,580,973 and 10,563,297
shares issued at September 30, 2013 and December 31, 2012, respectively)		105,810			105,633
Additional paid-in capital		36,623,965			36,524,142
Accumulated deficit		(27,959,990	)		(20,008,935	)
Treasury stock, 150,000 shares and 0 shares, respectively, at cost		(800,000	)		-
Total stockholders' equity		7,969,785			16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	51,338,719		$	56,381,926

See accompanying notes to condensed consolidated financial statements.

3

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUE FROM OPERATIONS
Refined product sales	$	106,541,284		$	103,738,982		$	320,025,559		$	233,926,241
Pipeline operations		78,909			117,712			229,162			312,098
Oil and gas sales		200			5,785			200			13,067
Total revenue from operations		106,620,393			103,862,479			320,254,921			234,251,406
COST OF OPERATIONS
Cost of refined products sold		105,314,208			96,160,575			317,508,586			229,853,030
Refinery operating expenses		2,629,518			2,559,456			8,099,371			5,862,121
Pipeline operating expenses		40,813			107,534			122,592			344,654
Lease operating expenses		16,797			18,653			58,088			63,612
General and administrative expenses		387,100			442,132			1,333,203			1,702,439
Depletion, depreciation and amortization		337,156			452,142			997,671			1,170,927
Abandonment expense		8			539,996			51,360			539,996
Accretion expense		28,173			29,118			84,513			79,868
Total cost of operations		108,753,773			100,309,606			328,255,384			239,616,647
Income (loss) from operations		(2,133,380	)		3,552,873			(8,000,463	)		(5,365,241	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		278,349			81,365			835,048			256,684
Interest and other income		668			16,439			2,480			20,354
Interest expense		(226,374	)		(74,227	)		(788,143	)		(583,077	)
Total other income (expense)		52,643			23,577			49,385			(306,039	)
Income (loss) from continuing operations before income taxes		(2,080,737	)		3,576,450			(7,951,078	)		(5,671,280	)
Income tax expense, current		-			(2,503	)		-			(15,647	)
Income (loss) from continuing operations, net of tax		(2,080,737	)		3,573,947			(7,951,078	)		(5,686,927	)
Loss from discontinued operations, net of tax		-			(4,336,708	)		-			(4,443,566	)
Net loss	$	(2,080,737	)	$	(762,761	)	$	(7,951,078	)	$	(10,130,493	)
Basic income (loss) per common share
Continuing operations	$	(0.20	)	$	0.34		$	(0.76	)	$	(0.56	)
Discontinued operations	$	-		$	(0.41	)	$	-		$	(0.43	)
Basic loss per common share	$	(0.20	)	$	(0.07	)	$	(0.76	)	$	(0.99	)
Diluted income (loss) per common share
Continuing operations	$	(0.20	)	$	0.34		$	(0.76	)	$	(0.56	)
Discontinued operations	$	-		$	(0.41	)	$	-		$	(0.43	)
Diluted loss per common share	$	(0.20	)	$	(0.07	)	$	(0.76	)	$	(0.99	)
Weighted average number of common shares outstanding:
Basic		10,421,731			10,545,690			10,450,906			10,191,980
Diluted		10,421,731			10,545,690			10,450,906			10,191,980

See accompanying notes to condensed consolidated financial statements.

4

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2013			2012
OPERATING ACTIVITIES
Net loss	$	(7,951,078	)	$	(10,130,493	)
Loss from discontinued operations		-			4,443,566
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization		997,671			1,162,362
Impairment of oil and gas properties					3,858,427
Unrealized gain on derivatives		(297,020	)		(21,470	)
Amortization of debt issue costs		25,350			25,349
Amortization of intangible assets		9,463			8,565
Accretion expense		84,513			79,868
Abandonment costs incurred		51,360			(141,099	)
Common stock issued for services		100,000			119,000
Bad debt expense		-			321,732
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash		62,210			(810	)
Accounts receivable		6,358,937			(7,852,717	)
Prepaid expenses and other current assets		(186,467	)		119,529
Deposits		(213	)		(763,421	)
Inventory		(2,085,969	)		(312,766	)
Accounts payable, accrued expenses and other liabilities		(3,395,086	)		8,057,321
Accounts payable, related party		1,665,782			2,275,665
Net cash provided by (used in) operating activities - continuing operations		(4,560,547	)		1,248,608
Net cash used in operating activities - discontinued operations		-			(4,293,887	)
Net cash used in operating activities		(4,560,547	)		(3,045,279	)
INVESTING ACTIVITIES
Capital expenditures		(1,244,859	)		(2,568,449	)
Proceeds from sale of assets		201,000			-
Cash acquired on acquisition		-			1,674,594
Net cash used in investing activities		(1,043,859	)		(893,855	)
FINANCING ACTIVITIES
Proceeds from issuance of debt		5,750,611			4,788,623
Payments on long-term debt		(60,876	)		(713,686	)
Proceeds from notes payable		15,032			24,548
Payments on notes payable		(206,445	)		(22,900	)
					-
Net cash provided by financing activities		5,498,322			4,076,585
Net increase (decrease) in cash and cash equivalents		(106,084	)		137,451
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		420,896			1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	314,812		$	139,273
Supplemental Information:
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received
Non-cash investing and financing activities:	$	800,000		$	-
Financing of insurance premiums	$	-		$	82,560
Related party payable converted to equity	$	0		$	993,732
Acquisition of Blue Dolphin at fair value, inclusive
of cash acquired of $1,674,594	$	-		$	18,046,154
Accrued services payable converted to common stock	$	100,000		$	119,000

See accompanying notes to condensed consolidated financial statements.

5

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(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 asset is a fifty-six (56) acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (4) Business Segment Information” 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);

●   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 $314,812 and $420,896 at September 30, 2013 and December 31, 2012, respectively.  We have incurred recurring losses from operations and continue to experience a working capital deficit and negative cash flows from operations. We are currently in violation of debt to worth and current ratio covenants in a loan agreement dated September 29, 2008 (the “Loan Agreement”) between LE and 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”). We are currently making our scheduled payments in accordance with the terms and conditions of the Refinery Note and seeking a waiver for the financial ratio covenants.  The lender has not declared an event of default of the Refinery Note. See “Note (17) 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 by and between LE and GEL TEX Marketing, LLC, an affiliate of Genesis (“GEL”), dated August 12, 2011 (the “Joint Marketing Agreement”), and Lazarus Energy Holdings, LLC (“LEH”) 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 GEL and/or LEH will continue to fund our working capital requirements.  In the event our working capital requirements are not funded by our profit share, GEL and/or LEH, we may experience a significant and material adverse effect on our operations.

We believe that our operational strategy, including our recent production of jet fuel and the refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility, 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 that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.  See “Item 1A. Risk Factors” in our previously filed Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”) and “Part II, Item 1A. Risk Factors” in our previously filed Quarterly Reports on Form 10-Q for the three months ended March 31, 2013 and the three months ended June 30, 2013 for risk factors related to working capital and liquidity.

 (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”). The 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.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (12) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

6

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

 (3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the 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 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 $314,812 and $420,896 at September 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,383 and $89,593 at September 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments

Accounts Receivable, Allowance for Doubtful Accounts and Concentrations 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 receivables for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit 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 balances of $59,852 and $170,896 at September 30, 2013 and December 31, 2012, respectively.

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, 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.

For the three months ended September 30, 2012, we had 3 customers that accounted for approximately 81% of our refined petroleum product sales.  These 3 customers represented approximately $4.9 million in accounts receivable at September 30, 2012.  For the nine months ended September 30, 2012, we had 4 customers that accounted for approximately 83% of our refined petroleum product sales.  These 4 customers represented approximately $6.0 million in accounts receivable at September 30, 2012.

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.

7

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis Energy, LLC (“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 condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed 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 charged to expense as incurred. Management expects to continue making improvements to our refinery assets 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, 2013 and 2012.

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, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets in 2012, 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.

Intangibles – Goodwill and Other

Goodwill. We recognized goodwill in connection with our reverse merger with LE. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with FASB ASC guidance related to intangibles, goodwill and other. We perform an impairment test annually in the fourth quarter.

Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.

8

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment,” in connection with the performance of our annual goodwill impairment testing. Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.

The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill during the fourth quarter of 2012.  The impairment recognized during 2012 represented 100% of goodwill.

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE. 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, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2012.

Debt Issue Costs

We have debt issue costs related to certain of our 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 $506,985 and $532,335 at September 30, 2013 and December 31, 2012, respectively.  Accumulated amortization was $168,995 and $143,645 at September 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note.  For the three and nine months ended September 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  For the three and nine months ended September 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  See “Note (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including 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 Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at September 30, 2013 was not material.

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 (20) Income Taxes” for further details.

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 comparison of 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.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Asset Retirement Obligations

FASB ASC guidance related to AROs requires that a liability for the discounted fair value of an asset retirement obligation 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 a quarterly 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 transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold 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 the unaudited consolidated statement 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 stock 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. For periods in which we have a net loss, we exclude stock options because their effect would be anti-dilutive.

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.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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 the consolidated statement of income 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 condensed 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 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 assets acquired, including identifiable intangibles 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

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation.

New Pronouncements Issued but Not Yet Effective

We have evaluated recent accounting pronouncements that are not yet effective and determined that they do not have a material impact on our consolidated financial statements or disclosures.

(4) Business Segment Information

We are engaged in three lines of business: (i) refinery operations, (ii) pipeline transportation and (iii) oil and gas exploration and production. As part of our refinery operations business segment, we also conduct petroleum storage and terminaling operations. Our primary operating asset is the Nixon Facility. We also operate oil and natural gas pipelines in the Gulf of Mexico and hold oil and natural gas leasehold interests in the U.S. Gulf of Mexico; however, these operations are considered non-core to our business. Management uses earnings before interest, income taxes and depreciation ("EBITDA") to assess the operating results and effectiveness of our business segments.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	106,541,284		$	78,909		$	200		$	-		$	106,620,393
Operation cost(2)		(107,961,900	)		(93,308	)		(20,797	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(1,142,267	)	$	(14,399	)	$	(20,597	)	$	(340,612	)
Depletion, depreciation and amortization														(337,156	)
Other expense, net														(225,706	)
Loss from continuing operations,													$	(2,080,737	)
before income taxes
Capital expenditures	$	356,889		$	-		$	-		$	-		$	356,889
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Segment financials for the three months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Three Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	103,738,982		$	117,712		$	5,785		$	-		$	103,862,479
Operation cost(2)		(98,755,479	)		(211,114	)		(730,774	)		(160,097	)		(99,857,464	)
Other non-interest income		81,365			-			-			-			81,365
EBITDA	$	5,064,868		$	(93,402	)	$	(724,989	)	$	(160,097	)
Depletion, depreciation and amortization														(452,142	)
Other expense, net														(57,788	)
Income from continuing operations,													$	3,576,450
before income taxes
Loss from discontinued operations													$	(4,336,708	)
Capital expenditures	$	494,312		$	-		$	-		$	-		$	494,312
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	320,025,559		$	229,162		$	200		$	-		$	320,254,921
Operation cost(2)		(325,625,984	)		(312,209	)		(120,856	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			-			835,048
EBITDA	$	(4,765,377	)	$	(83,047	)	$	(120,656	)	$	(1,198,664	)
Depletion, depreciation and amortization														(997,671	)
Other expense, net														(785,663	)
Loss from continuing operations,													$	(7,951,078	)
before income taxes
Capital expenditures	$	1,244,859		$	-		$	-		$	-		$	1,244,859
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Segment financials for the nine months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Nine Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	233,926,241		$	312,098		$	13,067		$	-		$	234,251,406
Operation cost(2)		(235,987,724	)		(648,334	)		(1,153,146	)		(656,516	)		(238,445,720	)
Other non-interest income		256,684			-			-			-			256,684
EBITDA	$	(1,804,799	)	$	(336,236	)	$	(1,140,079	)	$	(656,516	)
Depletion, depreciation and amortization														(1,170,927	)
Other expense, net														(562,723	)
Loss from continuing operations,													$	(5,671,280	)
before income taxes
Loss from discontinued operations													$	(4,443,566	)
Capital expenditures	$	2,568,449		$	-		$	-		$	-		$	2,568,449
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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16

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(5) 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 books and 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, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at September 30, 2013 and December 31, 2012 was $21,348,742 and $15,850,418, respectively. Accrued interest associated with our long-term debt and short-term notes payable at September 30, 2013 and December 31, 2012 was $1,670,188 and $1,499,136, respectively.  The following table represents our assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and the basis for that measurement:

	Fair Value Measurement at September 30, 2013 Using
Financial assets:	Carrying Value as at September 30, 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	$	160,920	$	160,920	$	-	$	-

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

(6) 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 the consolidated balance sheets and the related net gain or loss is recorded within cost of refined petroleum products sold in the 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.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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 their 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, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -
net short (long) positions		45,000		-		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in the consolidated balance sheets at September 30, 2013 and December 31, 2012: 

		September 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	160,920	$	(136,100	)

The following table provides the effect of derivative instruments on the consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012: 

		Gain (Loss) Recognized
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives	Statements of Operation Location	2013			2012			2013			2012
Commodity contracts	Cost of refined products sold	$	(297,179	)	$	(177,201	)	$	(330,320	)	$	(305,785	)

(7) Concentration of Risk

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2019.

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 in place with most of our customers. 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.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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,
	2013			2012			2013			2012
Low-sulfur diesel		44.9	%		49.7	%		48.2	%		47.4	%
Naphtha		24.3	%		25.4	%		25.6	%		26.2	%
Atmospheric gas oil		26.0	%		24.9	%		24.5	%		26.1	%
Reduced crude		0.0	%		0.0	%		0.1	%		0.3	%
Jet fuel		4.8	%		0.0	%		1.6	%		0.0	%
		100.0	%		100.0	%		100.0	%		100.0	%

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable product.  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.

(8) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	September 30,		December 31,
	2013		2012
Prepaid insurance	$	78,848	$	185,814
Prepaid professional fees		141,500		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		160,920		-
	$	414,781	$	228,314

(9) Deposits

Deposit balances consisted of the following:

	September 30,		December 31,
	2013		2012
Utility deposits	$	27,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,236,660	$	1,236,447

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(10) Inventories

Inventory balances consisted of the following:

	September 30,		December 31,
	2013		2012
Low-sulfur diesel	$	399,869	$	397,240
Naphtha		1,450,931		1,562,055
Jet fuel		1,715,129		-
Atmospheric gas oil		801,691		322,356
Crude		19,041		19,041
	$	4,386,661	$	2,300,692

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable product.  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.

(11) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	September 30,		December 31,
	2013		2012
Refinery and facilities	$	35,696,393	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		559,486		577,567
		38,393,090		36,714,977
Less: Accumulated depletion, depreciation and amortization		2,671,821		1,674,151
		35,721,269		35,040,826
Construction in Progress		187,004		821,259
Property, Plant and Equipment, Net	$	35,908,273	$	35,862,085

(12) Discontinued Operations

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky Langsa, Limited (“Blue Sky”) to dispose of its 7% undivided working interest in Indonesia.  As a result, our operations related to Indonesia ceased effective November 6, 2012 and the disposal was completed on February 28, 2013.  Operations associated with Indonesia, which were previously reported as part of the Oil and Gas Exploration & Production business segment, have been classified as discontinued operations and are presented in a separate line in the consolidated statements of operations for all periods presented.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

The following is a summary of the operating results of our discontinued operations:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013		2012
Revenue	$	-	$	231,658		$	-	$	674,797
Lease operating expenses		-		332,809			-		788,525
Depletion, depreciation and amortization		-		45,240			-		124,811
Abandonment expense		-		-			-		-
Impairment expense		-		3,858,427			-		3,858,427
Bad debt expense		-		321,732			-		321,732
Accretion expense		-		10,158			-		24,868
Total costs and expenses		-		4,568,366			-		5,118,363
Loss from discontinued operations, net of tax	$	-	$	(4,336,708	)	$	-	$	(4,443,566	)

(13) Accounts Payable, Related Party

LEH, which owns approximately 80% of our issued and outstanding common stock, manages and operates the Nixon Facility and our other operations (the “Services”) pursuant to a Management Agreement dated February 15, 2012 (the “Management Agreement”).

Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments 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 Management 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 Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement, which has an initial term of three years and successive one year renewals until August12, 2019 unless sooner terminated by GEL with 180 days prior written notice [see "Note (24) Subsequent Events" of this report for additional disclosures related to the Joint Marketing Agreement], (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by our Board of Directors (the “Board”) and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended September 30, 2013 and 2012 were $2,629,518 (approximately $2.68 per barrel) and $2,559,456 (approximately $2.70 per barrel). Aggregate amounts expensed for Services at the Nixon Facility for the nine months ended September 30, 2013 and 2012 were $8,099,371 (approximately $2.73 per barrel) and $5,862,121 (approximately $2.76 per barrel).  At September 30, 2013 and December 31, 2012, the amounts outstanding to LEH were $3,259,803 and $1,594,021, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets.

Herbert N. Whitney, a member of our Board, also currently serves as a consultant to LEH. Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, is a member of LEH. Tommy L. Byrd, our interim Chief Financial Officer, Treasurer and Assistant Secretary, is also an employee of LEH.

21

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(14) Notes Payable

Our notes payable consists of a short-term note for financing costs and short-term capital leases, as follows:

	September 30,		December 31,
	2013		2012
Short-Term Note for Financing Costs	$	23,188	$	39,866
Short-Term Captial Leases		7,056		4,075
	$	30,244	$	43,941

Short-Term Note for Financing Costs.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing costs was $23,188 and $39,866 at September 30, 2013 and December 31, 2012, respectively.  The unsecured note, which bears interest at a base rate of 10% and a default rate of 18%, was originally due in January 2012.  The due date has been extended to December 2013. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $7,056 and $4,075 at September 30, 2013 and December 31, 2012, respectively.  Capital leases totaling $1,250, which were classified as long-term debt at December 31, 2012, have been re-classified to short-term debt at September 30, 2013 as they mature at various dates through February 2014.  These capital leases have interest rates ranging from 0% to 13.04%.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

 (15) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	September 30,		December 31,
	2013		2012
Excise taxes	$	764,749	$	292,303
Transportation		-		69,551
Other payable		238,902		134,501
Property taxes		40,500		-
Unrealized hedging loss		-		136,100
Unearned revenue		-		92,783
	$	1,044,151	$	725,238

22

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(16) 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 assets. Management believes that the Nixon Refinery and related facilities 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.

Oil and Gas Properties and Pipelines and Facilities Assets

We have AROs associated with the future abandonment, dismantlement and removal of our oil and gas properties, as well as our pipelines and facilities assets, as follows:

Asset retirment obligations at December 31, 2012	$	921,260
Liabilities settled		(8,243	)
Accretion expense		84,513
		997,530
Less:  current portion of asset retirement obligations		88,044
Asset retirement obligations, long-term balance
at September 30, 2013	$	909,486

For the three months ended September 30, 2013, we recognized $8 in abandonment expense for AROs 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. 

 (17) Long-Term Debt

Our long-term debt consists of notes payable, construction financing and capital leases, as follows:

	September 30,		December 31,
	2013		2012
Refinery Note	$	9,122,302	$	9,298,183
Construction and Funding Agreement		10,896,196		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		-		2,119
		21,318,498		15,806,477
Less: Current portion of long-term debt		20,018,498		1,816,960
	$	1,300,000	$	13,989,517

Refinery Note.  The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at September 30, 2013) 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 $9,122,302 and $9,298,183 at September 30, 2013 and December 31, 2012, respectively.  Interest was accrued on the Refinery Note in the amount of $37,148 and $250,070 at September 30, 2013 and December 31, 2012, respectively. See "Note (1) Organization- Operating Risks"of this report for additional disclosures related to the Refinery Note.

23

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

The Loan Agreement has two financial covenants relating to a current ratio and debt to worth. As of September 30, 2013, we were in violation of these covenants. Accordingly, the Refinery Note was included in the current portion of long-term debt on the condensed consolidated balance sheet as of September 30, 2013.

In October 2011, the Refinery Loan Documents were acquired by American First National Bank (“AFNB”).  On June 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.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  The principal balance outstanding on the Construction and Funding Agreement was $10,896,196 and $5,206,175 at September 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $617,988 and $386,695 at September 30, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with this obligation.

A covenant violation in the Loan Agreement, if not cured or waived, could potentially lead to the termination of the Construction and Funding Agreement. Accordingly, the principal balance outstanding on the Construction and Funding Agreement was included in the current portion of long-term debt on the consolidated balance sheet as of September 30, 2013.

See “Note (21) Commitments and Contingencies” and “Note (24) Subsequent Events” of this report for additional disclosures related to amendments and/or modifications to the Crude Supply Agreement, Construction and Funding Agreement and Joint Marketing Agreement.

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, 2013 and December 31, 2012.  Interest was accrued on the Notre Dame Debt in the amount of $1,014,356 and $858,784 at September 30, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with the Notre Dame Debt.

Pursuant to an Intercreditor and Subordination Agreement dated September 29, 2008, 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.

Pursuant to an Intercreditor and Subordination Agreement dated 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 Milam under the Construction and Funding Agreement.

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 the final maturity became July 1, 2015.

Capital Leases.  Capital lease obligations previously classified as long-term debt were reclassified to short-term notes payable in 2013 as they mature in February 2014.  Long-term capital lease obligations totaled $0 and $2,119 at September 30, 2013 and December 31, 2012.

24

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(18) Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month.  The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis.   For the three months ended September 30, 2013 and 2012, rent expense for the office lease was $25,161 and $26,061, respectively.  For the nine months ended September 30, 2013 and 2012, rent expense for the office lease was $76,382 and $78,182, respectively.

(19) Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia.  The non-cash transaction was completed on February 28, 2013.  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. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  As of September 30, 2013, there were 150,000 shares of treasury stock.

(20) Income Taxes

LE is a limited liability company and, prior to the Merger, its 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. Upon the Merger, LE became the subsidiary of Blue Dolphin and LE’s taxable income or NOLs flowed through to Blue Dolphin for federal and state income tax purposes.  However, Section 382 of the Internal Revenue Code imposes a limitation on Blue Dolphin’s use of LE’s NOLs.  The amount of NOLs subject to such limitations is approximately $18.8 million. Nevertheless, the NOLs generated subsequent to the Merger, approximately $14.7 million, is not subject to any such limitation. For the three and nine months ended September 30, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended September 30, 2013 and 2012, income tax expense was $0 and $2,503, respectively.  For the nine months ended September 30, 2013 and 2012, income tax expense was $0 and $15,647, respectively.  Income tax expense and benefit related to the State of Texas margins tax (“TMT”).  TMT 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.

(21) Commitments and Contingencies

Management Agreement

See “Note (13) Accounts Payable, Related Party” of this report for additional disclosures related to the Management 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. 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.

25

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

● 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 has continued to make 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 of LE (as defined below) 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. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and 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 the agreement between LE and GEL pursuant to which the parties will 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.

26

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(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 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 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 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 obligation 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

(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.

As of September 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $10,896,196.  As of September 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $7,253,059.

Lazarus Texas Refinery I, LLC (“LTRI”) Option

In June 2012, we purchased an exclusive option, which expires on December 31, 2013, from LEH to acquire all of the issued and outstanding membership interests of LTRI, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.

In the event we exercise the option to purchase the Ingleside Refinery, Blue Dolphin and LEH will enter into a definitive purchase and sale agreement. We paid LEH a fully refundable sum of $100,000 in cash as consideration to purchase the exclusive option.  Upon exercise of the exclusive option to purchase the Ingleside Refinery, we will assume all outstanding liabilities, including a note payable, and reimburse LEH for costs associated with the acquisition, refurbishment and environmental remediation of the site.  The parties continue to monitor such refurbishment and remediation efforts as a prerequisite to determining the purchase price. If there is a material difference between LEH’s expenditures for such remediation efforts and our desired purchase price, LEH has agreed to refund us the purchase price for the Ingleside Refinery option.

28

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

Lazarus Energy Development, LLC (“LED”) Option

In connection with the Merger, we purchased an exclusive option, which expires on December 31, 2013, from LEH to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option.

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 will have a material adverse effect on our results of operations.

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 diesel and other fuels; 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 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.

(22) Earnings Per Share

The following table provides reconciliation between basic and diluted loss per share on a continuing and discontinued operations basis:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Income (loss) from continuing operations, net of tax	$	(2,080,737	)	$	3,573,947		$	(7,951,078	)	$	(5,686,927	)
Loss from discontinued operations, net of tax		-			(4,336,708	)		-			(4,443,566	)
Net loss		(2,080,737	)		(762,761	)		(7,951,078	)		(10,130,493	)
Basic and diluted gain (loss) per common share
Continuing operations	$	(0.20	)	$	0.34		$	(0.76	)	$	(0.56	)
Discontinued operations	$	-		$	(0.41	)	$	-		$	(0.43	)
Basic and diluted loss per common share	$	(0.20	)	$	(0.07	)	$	(0.76	)	$	(0.99	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,731			10,545,690			10,450,906			10,191,980

Diluted EPS is computed by dividing net loss available to common stockholders by the weighted average number of shares of common stock outstanding.  For the three months ended September 30, 2012, none of the stock options outstanding under our 2000 Stock Incentive Plan ("the "Plan") were included in the computation of diluted earnings per share because the option exercise price was greater than the average market price of the common stock. Diluted EPS for the three and nine months ended September 30, 2013 and the nine months ended September 30, 2012 excludes stock options outstanding as they would be anti-dilutive.

For the three months ended September 30, 2012, the weighted average number of shares of common stock outstanding was computed as LE’s number of shares of common stock outstanding from January 1, 2012 to February 15, 2012 (the beginning of the period to the date of LE’s acquisition by Blue Dolphin) combined with Blue Dolphin’s number of shares of common stock outstanding from February 15, 2012 to September 30, 2012 (the date of LE’s acquisition by Blue Dolphin to the end of the period).  For the period prior to the date of LE’s acquisition by Blue Dolphin, LE’s number of shares of common stock was computed as LE’s one member unit prior to the acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

29

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(23) Stock Options

The Plan offers incentive awards to employees, including officers (whether or not they are directors), consultants and non-employee directors. The Plan was initially established by the Blue Dolphin Board on April 14, 2000 and approved by Blue Dolphin’s stockholders on May 18, 2000. The Plan was amended effective March 19, 2003 and ratified by Blue Dolphin’s stockholders on May 21, 2003 to increase the common stock available for issuance under the Plan from 500,000 shares to 650,000 shares (Amendment No. 1). The Plan was further amended effective April 5, 2007 and ratified by Blue Dolphin’s stockholders effective May 30, 2007 to increase the common stock available for issuance under the Plan from 650,000 shares to 1,200,000 shares (Amendment No. 2). Effective July 16, 2010, Blue Dolphin’s stockholders approved a 1-for-7 reverse-stock-split of its common stock, which reduced the number of shares of common stock available for issuance under the Plan from 1,200,000 shares to 171,128 shares (Amendment No. 3). Effective January 27, 2012, Blue Dolphin’s stockholders approved an amendment to the Plan to change the expiration date of the Plan from 10 to 20 years (to April 14, 2020), as well as increase the aggregate number of common stock available for issuance under the Plan from 171,128 shares to 1,000,000 shares (Amendment No. 4).  The Compensation Committee of the Board approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

Options granted under the Plan have contractual terms from 6 to 10 years. The exercise price of incentive stock options cannot be less than 100% of the fair market value of a share of our common stock determined on the grant date. Although the Plan provides for the granting of other incentive awards, only incentive stock options and non-statutory stock options have been issued under the Plan to date. The Plan is administered by the Compensation Committee of the Board.

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the three and nine months ended September 30, 2013.

At September 30, 2013, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

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Notes to Consolidated Financial Statements

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at September 30, 2013		14,642	$	19.67		0.1	$	-
Options exercisable at September 30, 2013		14,642	$	19.67		0.1	$	-

We recognized no compensation expense for vested stock options for the three and six months ended September 30, 2013 and 2012. As of September 30, 2013, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the three months ended September 30, 2013 and 2012, we recognized $50,000 and $0, respectively, of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.  For the nine months ended September 30, 2013 and 2012, we recognized $100,000 and $60,000, respectively, of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

(24) Subsequent Events

On October 30, 2013, LE entered into the October 2013 Letter Agreement with GEL and Milam, effective October 24, 2013.  The October 2013 Letter Agreement modified certain terms of the Crude Supply Agreement, the Construction and Funding Agreement (as amended, restated or supplemented from time to time), and the Joint Marketing Agreement (as amended, restated or supplemented from time to time).

In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and the Joint Marketing Agreement, and GEL agreed to automatically renew the Crude Supply Agreement and the Joint Marketing Agreement at the end of their respective initial terms for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.  In addition, GEL agreed to advance monies to LE 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.

Remainder of Page Intentionally Left Blank

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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 year ended December 31, 2012 (the “Annual Report”) and our Quarterly Reports on Form 10-Q for the three months ended March 31, 2013 and for the three months ended June 30, 2013.  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, 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 1. Legal Proceedings” relating to matters that are not historical fact 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 otherwise 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:

● the potential reorganization of Blue Dolphin from a publicly traded “C” corporation to a publicly traded master limited partnership;

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

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

● the positive or negative effects of Genesis’ hedging of our refined petroleum products and crude oil inventory;

● our reliance on Genesis and Lazarus Energy Holdings, LLC (“LEH”) to fund our working capital requirements ;

● our dependence on LEH for management of the Nixon Facility and our other operations;

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

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

● declaration of an event of default related to our long-term indebtedness;

● failure to comply with other forbearance agreements relating to our long-term indebtedness;

● potential downtime of the Nixon refinery for maintenance and repairs;

● access to less than desired levels of crude oil for processing at our crude oil and condensate processing facility located in Nixon, Texas;

● operating hazards such as fires and explosions;

● insurance coverage limitations;

● environmental costs and liabilities associated with our operations;

● retention of key personnel;

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

● costs of abandoning our pipelines and oil and gas properties;

● local and regional events that may negatively affect our assets;

● competition from larger companies;

● acquisition expenses and integration difficulties; and

● compliance with environmental and other regulations, including greenhouse gas emissions regulations, the effects of the Renewable Fuels Standard program and oxygenate blending requirements.

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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,” “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.  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refinery Operations

Our primary business is the refining of crude oil into marketable finished and refined products at the Nixon Facility, which is a crude oil and condensate processing facility with a current operating capacity of approximately 15,000 barrels (“bbls”) per day (“bpd”). The Nixon Facility is located on a 56-acre site in Nixon, Wilson County, Texas, and consists of a distillation unit, naphtha stabilizer, recovery facilities with approximately 120,000 bbls of crude oil storage capacity and 148,000 bbls of refined product storage capacity, as well as related loading and unloading facilities and utilities.

We purchase crude oil and condensate for the Nixon Facility under an exclusive supply agreement with GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis, and have the ability to produce refined products such as Non-Road Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), kerosene, jet fuel and intermediate products, including liquefied petroleum gas (“LPG”), naphtha and atmospheric gas oil.  The Nixon Facility is operated as a “topping unit,” processing light crude oil and condensate from south Texas, including the Eagle Ford Shale formation, into NRLM for sale into nearby markets and naphtha and atmospheric gas oil for sale to nearby refineries for further processing.  Although we currently receive feedstock by truck, the Nixon Facility has the ability to receive crude oil and condensate via pipeline.  Our refined products are currently sold and delivered by truck and barge.

Pipeline Transportation

Our pipeline operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines in the U.S. Gulf of Mexico. Producers and shippers are charged a fee based on anticipated throughput volumes.

Oil and Gas Exploration and Production

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the three and nine months ended September 30, 2013 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company (‘BDEX”), a wholly owned subsidiary, completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.  For the three and nine months ended September 30, 2013, our oil and gas exploration and production business segment had no revenue.

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Operational Strategy

We are dedicated to maintaining efficient and reliable refinery operations and improving liquidity and profitability.   Throughout 2013, we have taken a number of steps to more effectively operate the Nixon Facility and manage the spread between our cost to acquire crude oil and the price of the refined petroleum products that we ultimately sell.  Such steps to date have included adopting a condition-based predictive maintenance turnaround policy and completion of several smaller capital improvement projects, such as installation of new laboratory equipment and a new caustic system.  Progress on our operational strategy for the three months ended September 30, 2013 (the “Current Quarter”) was as follows:

●   Sale of Jet Fuel – In mid-September of the Current Quarter, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable product.  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; and

●   Refurbishment of Naphtha Stabilizer and Depropanizer Unit – We are refurbishing the naphtha stabilizer and depropanizer units at the Nixon Facility, which we anticipate will: (i) improve the quality of the naphtha that we produce, (ii) allow higher recovery of lighter products that can be sold as a LPG mix, and (iii) increase the amount of throughput that can be processed by the Nixon Facility.  The estimated cost to refurbish the naphtha stabilizer and depropanizer unit is approximately $1.5 million. Our ability to complete this capital expenditure project is dependent upon further advances being made by Milam under the Construction and Funding Agreement, cash from operations or third-party financing.  There can be no assurance that funding will be obtained for completion of the capital expenditure project.  (See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for additional disclosures that add to our obligation amount under the Construction and Funding Agreement.)

Key Operating Statistics

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Nixon Facility
Operating days		90			90			265			238
Total refinery throughput(1)
bbls		979,807			947,569			2,967,469			2,125,094
bpd		10,887			10,529			11,198			8,929
Capacity utilization rate		73	%		70	%		75	%		60	%
Total refinery production
bbls		963,645			925,048			2,906,873			2,085,970
bpd		10,707			10,283			10,969			8,765
Capacity utilization rate		71	%		69	%		73	%		58	%

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

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Major Influences on Results of Operations

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, the availability of imports, the marketing of competitive fuels and government regulation.

In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. 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 has the capability to process substantial volumes of low-sulfur crude oils (sweet crude) to produce a high percentage of light, high-value refined petroleum products. Sweet crude derived from the surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s crude oil input.

Safety, reliability and the environmental performance of the Nixon Facility is critical to our financial performance. The 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.

The nature of our business requires us to maintain 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.

Critical Accounting Policies and Estimates

We prepare our financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”). In order to apply these principles, we must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the continuing development of the information utilized and subsequent events, some of which we may have little or no control over. Our critical accounting policies could materially affect the amounts recorded in our financial statements. Our critical accounting policies, estimates and recent accounting pronouncements that potentially impact us are discussed in detail under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report.

Recent Accounting Pronouncements.  From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board or other standard setting bodies that may have an impact on our accounting and reporting. We believe that such recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have a significant impact on our accounting or reporting or that such impact will not be material to our financial position, results of operations and cash flows when implemented.

Relationship with Genesis

We continue to be dependent on our relationship with Genesis and its affiliates. Our relationship with Genesis is governed primarily 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., an affiliate of Genesis (“Milam”), 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”).

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Below is a discussion of the material terms and conditions of each of our agreements with Genesis.

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL 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. 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.

● 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 has continued to make 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 of LE (as defined below) 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. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at anytime. 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 the agreement between LE and GEL pursuant to which the parties will 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:

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(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 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 modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing 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 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.

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(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 obligation 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.

As of September 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $10,896,196.  As of September 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $7,253,059.

Results of Operations

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012 (the “Prior Quarter”)

During the Prior Quarter, the Nixon Facility, which was refurbished and began operations in February 2012, operated for a total of 90 days at 70% of operating capacity.  During the Current Quarter, the Nixon Facility operated for 90 days at 73% of operating capacity.

Current Quarter Compared to Prior Quarter

Summary. For the Current Quarter we reported a loss from continuing operations, net of tax, of $2,080,737, or a loss of $0.20 per share, compared to income from continuing operations, net of tax, of $3,573,947, or income of $0.34 per share, for the Prior Quarter.  We reported a loss from discontinued operations of $4,336,708, or a loss of $0.41 per share, in the Prior Quarter compared to no loss from discontinued operations in the Current Quarter.   The loss from continuing operations, net of tax, in the Current Quarter was primarily attributable to lower refining margins. Refining gross margin per barrel sold was $1.29 for the Current Quarter compared to $8.19 for the Prior Quarter.

Total Revenue from Operations. For the Current Quarter we had total revenue from operations of $106,620,393 compared to total revenue from operations of $103,862,479 for the Prior Quarter.  The 3% increase in total revenue from operations was primarily the result of an increase in refined product sales at the Nixon Facility.  Substantially all of our revenue in the Current Quarter came from refined product sales, which generated revenue of $106,541,284, or more than 99% of total revenue from operations, compared to $103,738,982, 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 $105,314,208 for the Current Quarter compared to $96,160,575 for the Prior Quarter.  The 10% increase in cost of refined products sold was primarily the result of an increase in the cost of crude oil per barrel and an increase in the volume of refined products sold.

Refinery Operating Expenses. We recorded refinery operating expenses of $2,629,518 in the Current Quarter, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH.  For the Prior Quarter, we recorded refinery operating expenses of $2,559,456.  See “Part I, Item 1. Financial Statements - Note (13), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $40,813 in the Current Quarter compared to $107,534 in the Prior Quarter.  The decline in pipeline operating expenses was the result of lower throughput on our pipeline systems.

Lease Operating Expenses. Lease operating expenses totaled $16,797 in the Current Quarter compared to $18,653 in the Prior Quarter.  The decline in lease operating expenses was due to leases being relinquished and fields being shut-in by operators.

General and Administrative Expenses. General and administrative expenses decreased from $442,132 in the Prior Quarter to $387,100 in the Current Quarter. The decrease in general and administrative expenses in the Current Quarter was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization decreased from $452,142 in the Prior Quarter to $337,156 in the Current Quarter.  We recorded a significant impairment to our pipeline and oil and gas assets in 2012, which reduced the carrying value of these assets and resulted in a corresponding decrease in depletion, depreciation and amortization expense.

Abandonment Expense. We recognized $8 of abandonment expense in the Current Quarter compared to $539,996 in the Prior Quarter.  Abandonment expense in the Prior Quarter primarily related to plugging and abandonment costs associated with our High Island A-7 oil and gas property.  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. 

Other Income. We recognized $278,349 in net tank rental revenue in the Current Quarter compared to $81,365 in the Prior Quarter.  The increase in net tank rental revenue was primarily a result of additional tanks being leased.

Discontinued Operations, Net of Tax.  We reported a loss from discontinued operations, net of tax, of $4,336,708 in the Prior Quarter compared to $0 in the Current Quarter.

Nine Months Ended September 30, 2013 (the “Current Nine Months”) Compared to Nine Months Ended September 30, 2012 (the “Prior Nine Months”)

During the Prior Nine Months, the Nixon Facility, which was refurbished and began operations in February 2012, operated for a total of 238 days at 60% of operating capacity.  During the Current Nine Months, the Nixon Facility operated for 265 days at 75% of operating capacity.

Current Nine Months Compared to Prior Nine Months

Summary. For the Current Nine Months we reported a loss from continuing operations, net of tax, of $7,951,078, or a loss of $0.76 per share, compared to a loss from continuing operations, net of tax, of $5,686,927, or a loss of $0.56 per share, for the Prior Nine Months.  We reported a loss from discontinued operations of $4,443,566, or a loss of $0.43 per share, in the Prior Nine Months compared to no loss from discontinued operations in the Current Nine Months.   The loss from continuing operations, net of tax, in the Current Nine Months was primarily attributable to lower refining margins combined with lost sales as a result of a planned maintenance turnaround during the first quarter of 2013.  During the Current Nine Months, we adopted a condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, such as installation of new laboratory equipment and a new caustic system, to enhance profitability of our existing assets.

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Blue Dolphin Energy Company & Subsidiaries

Total Revenue from Operations. For the Current Nine Months we had total revenue from operations of $320,254,921 compared to total revenue from operations of $234,251,406 for the Prior Nine Months.   The increase in total revenue from operations was primarily the result of operating 27 more days and increased throughput at the Nixon Facility 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 $320,025,559, or more than 99% of total revenue from operations, compared to $233,926,241, 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 $317,508,586 for the Current Nine Months compared to $229,853,030 for the Prior Nine Months.  The increase in cost of refined products sold was primarily the result operating 27 more days and increased throughput at the Nixon Facility in the Current Nine Months compared to the Prior Nine Months.

Refinery Operating Expenses. We recorded refinery operating expenses of $8,099,371 in the Current Nine Months, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH.  For the Prior Nine Months, we recorded refinery operating expenses of $5,862,121.  See “Part I, Item 1. Financial Statements - Note (13), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $122,592 in the Current Nine Months compared to $344,654 in the Prior Nine Months.  The decline in pipeline operating expenses was the result of lower throughput on our pipeline systems.

Lease Operating Expenses. Lease operating expenses totaled $58,088 in the Current Nine Months compared to $63,612 in the Prior Months.

General and Administrative Expenses. General and administrative expenses decreased from $1,702,439 in the Prior Nine Months to $1,333,203 in the Current Nine Months. The decrease in general and administrative expenses in the Current Nine Months was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization decreased from $1,170,927 in the Prior Nine Months to $997,671 in the Current Nine Months.    We recorded a significant impairment to our pipeline and oil and gas assets in 2012, which reduced the carrying value of these assets and resulted in a corresponding decrease in depletion, depreciation and amortization expense.

Abandonment Expense. We recognized $51,360 of abandonment expense in the Current Nine Months compared to $539,996 in the Prior Nine Months.  Abandonment expense in the Prior Nine Months was primarily related to plugging and abandonment costs associated with our High Island A-7 oil and gas property.  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. 

Other Income. We recognized $835,048 in net tank rental revenue in the Current Nine Months compared to $256,684 in the Prior Nine Months.  The increase in net tank rental revenue was primarily a result of additional tanks being leased.

Discontinued Operations, Net of Tax.  We reported a loss from discontinued operations, net of tax, of $4,443,566 in the Prior Nine Months compared to $0 in the Current Nine Months.

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

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. EBITDA is adjusted for: (i) items that do not impact our income or loss from continuing operations, such as the impact of accounting changes, (ii) income taxes and (iii) interest income (expense), depreciation and amortization. We exclude interest expense (or income) and other expenses or income not pertaining to the operations of our segments from this measure 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.

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Blue Dolphin Energy Company & Subsidiaries

Following is a reconciliation of EBITDA by business segment for the three months ended September 30, 2013 (and at September 30, 2013) and the three months ended September 30, 2012 (and at September 30, 2012):

	Three Months Ended September 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	106,541,284		$	78,909		$	200		$	-		$	106,620,393
Operation cost(2)		(107,961,900	)		(93,308	)		(20,797	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(1,142,267	)	$	(14,399	)	$	(20,597	)	$	(340,612	)	$	(1,517,875	)
Depletion, depreciation and amortization														(337,156	)
Other expense, net														(225,706	)
Loss from continuing operations,													$	(2,080,737	)
before income taxes
Capital expenditures	$	356,889		$	-		$	-		$	-		$	356,889
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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41

Blue Dolphin Energy Company & Subsidiaries

	Three Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	103,738,982		$	117,712		$	5,785		$	-		$	103,862,479
Operation cost(2)		(98,755,479	)		(211,114	)		(730,774	)		(160,097	)		(99,857,464	)
Other non-interest income		81,365			-			-			-			81,365
EBITDA	$	5,064,868		$	(93,402	)	$	(724,989	)	$	(160,097	)	$	4,086,380
Depletion, depreciation and amortization														(452,142	)
Other expense, net														(57,788	)
Income from continuing operations,													$	3,576,450
before income taxes
Loss from discontinued operations													$	(4,336,708	)
Capital expenditures	$	494,312		$	-		$	-		$	-		$	494,312
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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42

Blue Dolphin Energy Company & Subsidiaries

Following is a reconciliation of EBITDA by business segment for the nine months ended September 30, 2013 (and at September 30, 2013) and the nine months ended September 30, 2012 (and at September 30, 2012):

	Nine Months Ended September 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	320,025,559		$	229,162		$	200		$	-		$	320,254,921
Operation cost(2)		(325,625,984	)		(312,209	)		(120,856	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			-			835,048
EBITDA	$	(4,765,377	)	$	(83,047	)	$	(120,656	)	$	(1,198,664	)	$	(6,167,744	)
Depletion, depreciation and amortization														(997,671	)
Other expense, net														(785,663	)
Loss from continuing operations,													$	(7,951,078	)
before income taxes
Capital expenditures	$	1,244,859		$	-		$	-		$	-		$	1,244,859
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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43

Blue Dolphin Energy Company & Subsidiaries

	Nine Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	233,926,241		$	312,098		$	13,067		$	-		$	234,251,406
Operation cost(2)		(235,987,724	)		(648,334	)		(1,153,146	)		(656,516	)		(238,445,720	)
Other non-interest income		256,684			-			-			-			256,684
EBITDA	$	(1,804,799	)	$	(336,236	)	$	(1,140,079	)	$	(656,516	)	$	(3,937,630	)
Depletion, depreciation and amortization														(1,170,927	)
Other expense, net														(562,723	)
Loss from continuing operations,													$	(5,671,280	)
before income taxes
Loss from discontinued operations													$	(4,443,566	)
Capital expenditures	$	2,568,449		$	-		$	-		$	-		$	2,568,449
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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44

Blue Dolphin Energy Company & Subsidiaries

Liquidity and Capital Resources

Sources and Uses of Cash.

	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2013			2012			2013			2012
Cash flow from operations
Adjusted loss from continuing operations	$	(1,738,670	)	$	7,957,949		$	(6,979,741	)	$	(274,193	)
Adjusted loss from discontinued operations		-			(4,281,310	)					(4,293,887	)
Change in assets and current liabilities		333,837			(3,704,656	)		2,419,194			1,522,801
Total cash flow from operations		(1,404,833	)		(28,017	)		(4,560,547	)		(3,045,279	)
Cash inflows (outflows)
Proceeds from issuance of debt		2,045,420			535,776			5,750,611			4,788,623
Payments on long term debt		-			(357,035	)		(60,876	)		(713,686	)
Cash acquired on Acquisition		-			-			-			1,674,594
Capital expenditures		(356,889	)		(494,312	)		(1,244,859	)		(2,568,449	)
Proceeds from sale of assets		-			-			201,000			-
Proceeds from notes payable		-			8,548			15,032			24,548
Payments on note payble		(149,705	)		(3,975	)		(206,445	)		(22,900	)
Total cash inflows (outflows)		1,538,826			(310,998	)		4,454,463			3,182,730
Total change in cash flows	$	133,993		$	(339,015	)	$	(106,084	)	$	137,451

At September 30, 2013, our available cash was $314,812.  We are currently relying on our profit share, GEL and LEH to fund our working capital requirements. During months in which we receive no profit share distribution, GEL and/or LEH may, but are not required to, fund our operating losses. As of September 30, 2013, the Deficit Amount financed by GEL was $7,253,059 and the working capital amount funded by LEH was $3,259,803.  For months in which GEL finances Deficit Amounts, LE does not receive any of its profit share until the Deficit Amounts have been repaid.

We believe that our aforementioned operational strategy will be sufficient to support our operations over the next 12 months.  (See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operational Strategy” of this report for disclosures related to our operational strategy.) 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 our profit share, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.  See “Item 1A. Risk Factors” in our previously filed Annual Report, "Part II, Item 1A. Risk Factors" in our previously filed Quarterly Reports for the three months ended March 31, 2013 and the three months ended June 30, 2013, and "Part II, Item 1A. Risk Factors" in this report for the risk factors related to working capital and liquidity.

For the Current Quarter, we experienced negative cash flow from operations of $1,404,833.  For the Prior Quarter, we experienced negative cash flow from operations of $28,017. This represents a decline in cash flow from operations of $1,376,816 for the Current Quarter compared to the same period a year earlier.

We continue to work with our vendors to bring our outstanding accounts payable current as expeditiously as possible. In the event that our efforts are not successful, we will experience a significant and material adverse effect on our continuing operations, liquidity and financial condition.

45

Blue Dolphin Energy Company & Subsidiaries

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the three and nine months ended September 30, 2013 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company (‘BDEX”), a wholly owned subsidiary, completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.

We recognized $8 and $539,996 of abandonment expense in the Current Quarter and Current Nine Months, respectively, related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount for High Island A-7, which exceeded the asset retirement obligation liability, was recognized as a loss during the respective periods. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

Capital expenditures in the Current Quarter and Current Nine Months totaled $356,889 and $1,244,859, respectively, and consisted of $356,889 and $1,244,859, respectively, related to investments in the Nixon Facility.  We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $10,896,196 and $5,206,175, including Deficit Amounts, at September 30, 2013 and December 31, 2012, respectively.

The principal balance outstanding on the Refinery Note was $9,122,302 and $9,298,183 at September 30, 2013 and December 31, 2012, respectively. On June 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, 2013 and December 31, 2012. There are no financial covenants associated with this debt.

See “Part I, Item 1. Financial Statements – Note (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to our debt obligations.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk. We are exposed to market price risk related to our refined petroleum products and crude oil inventory. The spread between crude oil and refined product prices is the primary factor affecting our operations, liquidity and financial condition. Our crude acquisition costs and refined petroleum products sales prices depend on numerous factors beyond our control. These factors include the supply of and demand for crude oil, gasoline, NRLM and other refined petroleum products. Supply and demand for these products depend, among other things, on changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; production levels; availability of imports and exports; marketing of competitive fuels; and government regulation.

We utilize an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products and crude oil inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.

Interest Rate Risk. We are exposed to interest rate volatility with regard to existing variable rate debt tied to movements in the U.S. prime rate. At September 30, 2103, we had $9,122,302 of variable interest debt with a weighted average interest rate at year end of approximately 5.50%.

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.

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Blue Dolphin Energy Company & Subsidiaries

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, 2013.   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 months ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

47

Blue Dolphin Energy Company & Subsidiaries

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

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 will 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, you should carefully consider the factors discussed under Item 1A, “Risk Factors” and elsewhere in our previously filed Annual Report and Quarterly Reports on Forms 10-Q for the three months ended March 31, 2013 and for the three months ended June 30, 2013. 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 and Quarterly Reports on Form 10-Q for the three months ended March 31, 2013 and the three months ended June 30, 2013.

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

None.

ITEM 3  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6. EXHIBITS

(a) Exhibits:

The following exhibits are filed herewith:

Exhibit Number	Description
10.1	First Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of July 1, 2013.
10.2	Letter Agreement Regarding Certain Advances and Related Agreement between Lazarus Energy, LLC, GEL TEX Marketing, LLC, and Milam Services, Inc., effective October 24, 2013.
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.CA	XBRL Calculation Linkbase Document.
101.LAB	XBRL Label Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

48

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.

		By:  BLUE DOLPHIN ENERGY COMPANY
Date: November 14, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)
Date: November 14, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

49

EX-10.1

Exhibit 10.1

FIRSTAMENDMENT TO PROMISSORY NOTE

This FIRST AMENDMENT TO PROMISSORY NOTE (the "Amendment") by and between Lazarus Energy, LLC, a Delaware limited liability company ("Maker") and John H. Kissick ("Payee") is made effective as of July 1, 2013 (the "Effective Date").The Maker and the Payee shall be referenced individually as a "Party" and collectively and "Parties".

WHEREAS, the Maker and the Payee are Parties to that certain Promissory Note dated June 1, 2006, (as amended, restated, supplemented or otherwise modified from time to time in accordance with its provisions, the "Note") to which reference is hereby made for all purposes; and

WHEREAS, the Parties hereto desire to amend the Note on the terms and subject to the conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1.Definitions. Capitalized terms used and not defined in this Amendment shall have the respective meanings given them in the Note.

2.Amendments to the Note. The Note is hereby amended as follows:

(a)Interest Rate. The annual Interest Rate on Unpaid Balance shall be sixteen per cent (16.00%).

(b)Final Maturity. The Final Maturity shall be July 1, 2015.

3.Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Note and the Deed of Trust are and shall remain in full force and effect and are hereby ratified and confirmed by the Maker. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of Note or Deed of Trust or for any purpose except as expressly set forth herein or a consent to any further or future action on the part of the Maker that would require the waiver or consent of the Payee.

4.Successors and Assigns. This Amendment shall inure to the benefit of and be binding upon the Payee and Maker and each of their respective successors and assigns.

5.Counterparts. This Amendment may be executed in any number of counterparts, all of which shall constitute one and the same agreement, and any Party hereto may execute this Amendment by signing and delivering one or more counterparts. Delivery of an executed counterpart of this Amendment electronically or by facsimile shall be effective as delivery of an original executed counterpart of this Amendment

[Remainder of page intentionally left blank; signature page to follow.]

1

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment as of the Effective Date.

	Lazarus Energy, LLC, as Maker
Date	By:	/s/ JONATHAN P. CARROLL
	Name:	Jonathan P. Carroll
	Title:	Director
	John H. Kissick, as Payee
	By:	/s/ JOHN H. KISSICK
	Name:	John H. Kissick

2

EX-10.2

Exhibit 10.2

October 24, 2013

Lazarus Energy LLC

801 Travis, Suite 2100

Houston, Texas 77002

Attention: Jonathan Carroll

GEL TEX Marketing, LLC

Milam Services, Inc.

919 Milam, Suite 2100

Houston, Texas 77002

Attention: Steve Nathanson

Re: Letter Agreement Regarding Certain Advances and Related Agreements

Gentlemen:

Reference is made to that certain (i) Joint Marketing Agreement dated August 12, 2011 (as amended, restated or supplemented from time to time, the "JMA"), by and between Lazarus Energy LLC, a Delaware limited liability company ("Lazarus"), and GEL Tex Marketing, LLC, a Delaware limited liability company ("GEL"), (ii) Construction and Funding Contract dated August 12, 2011 (as amended, restated or supplemented from time to time, the "CFC"), by and between Lazarus and Milam Services, Inc., a Delaware corporation ("MSI"), (iii) Crude Oil Supply and Throughput Services Agreement dated August 12, 2011 by and between GEL and Lazarus, (iv) Letter Agreement dated June 25, 2012 by and between GEL, MSI and Lazarus regarding expense payments and reservations of rights ("Operating Expense Payment Letter Agreements"), (v) Acknowledgement Letter dated June 1, 2012 addressed to Lazarus by GEL (the "Acknowledgement Letter"), (vi) Letter Agreement Regarding Distribution to Recover December 31, 2012 Payment made to Lazarus dated December 20, 2012 ("December 2012 Payments Letter Agreement"), (vi) Letter Agreement Regarding Distributions to Recover Payment made to Settle Claims Against Lazarus dated February 21, 2013 ("Settlement Payment Distribution Letter"), and (vii) Letter Agreement Advances To Fund February 2013 Turnaround dated February 21, 2013 (the "2013 Turnaround Letter"). Capitalized terms not otherwise defined herein shall have the meanings set forth in the CFC.

The parties to this Letter Agreement desire to set forth certain acknowledgements and agree to certain modifications to the JMA, the CFC and the Supply Agreement, as more particularly set forth herein.

Section 1. Advances to pay for Equipment and Services at the Facility.

(a) GEL agrees to advance an amount equal to (1) $75,986.01, to be used by Lazarus exclusively to pay the invoices of Petroleum Measurement Equipment Company ("PEMC") that are attached as Exhibit A hereto, for equipment and services provided by PEMC at the Facility, (2) $50,947.95, to be used by Lazarus exclusively to pay the invoices of Guardian Compliance ("Guardian") that are attached as Exhibit B hereto, for equipment and services provided by Guardian at the Facility, (3) not more than $45,000, to be used by Lazarus exclusively to purchase from Ro-Flo Compressors LLC a Naphtha compressor, which shall be located and used exclusively at the Facility, and (4) not more than $15,000, to be used by Lazarus exclusively to purchase from a vendor pre-approved by GEL the firefighting equipment described on Exhibit C, which shall be located and used exclusively at the Facility.

(b)Lazarus shall provide to GEL true and correct copies of the invoices from the applicable suppliers of the equipment referenced in Section 1(a) (the "Equipment"), and such other information substantiating the charged amounts from the applicable suppliers of the Equipment. GEL, at its option, shall either pay such invoices directly to the supplier, or advance funds to Lazarus for contemporaneous payment by Lazarus to the applicable supplier in a manner acceptable to GEL, provided that GEL shall only pay or advance funds for Equipment that has been delivered to the Facility. The amounts to be paid or advanced by GEL for the Equipment shall not exceed for each item the amount specified in Section 1(a) for such item. GEL shall have the right to approve the vendor(s) and the compressor and firefighting equipment prior to any such purchase.

(c)All amounts advanced or paid by GEL or its Affiliates pursuant to this Letter Agreement shall constitute Obligations.

(d)In the event Lazarus breaches or otherwise fails to comply with any of its obligations under this Letter Agreement, in addition to any other remedies at law or equity available to GEL, GEL shall be entitled to have any and all Equipment referenced herein removed from the Facility and delivered to GEL.

1

Section 2. Certain Agreements.

(a)Commencing on the first date written above and continuing until and including August 12, 2019, Lazarus hereby waives its right to terminate the Supply Agreement pursuant to Section 2.1 thereof and its right to terminate the JMA pursuant to Section 7.1 thereof. Lazarus further hereby agrees that, unless sooner terminated by GEL with 180 days prior written notice, the Supply Agreement and the JMA shall be automatically renewed for successive one year terms at the expiration of the respective Initial Term (as such term is defined in such agreements) and at the expiration of each such successive one year term, in each case until August 12, 2019.

(b)Notwithstanding any provisions of the CFC, JMA, Supply Agreement or any Contract Document to the contrary, (1) to the extent that GEL's, Milam's or their respective Affiliates' ability to assign or otherwise transfer any of their rights or obligations in whole or in part under the CFC, JMA, Supply Agreement or any Contract Documents is restricted in any way by the terms of such applicable agreement, then such restrictions shall not apply to any such assignment or transfer to a prospective assignee or transferee that is financially responsible, creditworthy, and has significant industry qualifications and experience commiserate with that required to fulfill its obligations under such applicable agreement, and (2) GEL, Milam and their respective Affiliates have the right to provide any data or information relating the CFC, JMA, Supply Agreement or any Contract Document or any of them, the Facility or the Project to any prospective assignee or transferee and to their respective representatives with the understanding that any data or information relating to the CFC, JMA, Supply Agreement, any Contract Document, the Facility, or the Project may be confidential or proprietary, and any prospective assignee or transferee and their respective representatives shall execute a confidentiality agreement with respect to such confidential or proprietary data or information.

(c)Lazarus reaffirms that Operations Payments (as defined in the JMA) may only be used to pay Operating Expenses (as defined in the JMA) of the Facility. On or before the 5th day of each calendar month, Lazarus shall provide to GEL an itemized list of the Operating Expenses of the Facility, including detail by person and amount of salaries, that will be paid by the Operations Payment in such month. Upon request of GEL, Lazarus shall provide an accounting of use of the Operations Payments in prior months, including supporting documentation for any such uses.

(d)Lazarus agrees and acknowledges that the current outstanding aggregate balance of the Obligations as of August 31, 2013 owed by it to Milam and GEL is $11,364,862 Lazarus hereby ratifies all of its Obligations under the CFC and each of the Contract Documents to which it is a party, and agrees and acknowledges that the CFC and each of the Contract Documents to which it is a party shall continue in full force and effect after giving effect to this Letter Agreement. Without limiting the foregoing, Lazarus hereby specifically ratifies all liens and security interests granted to Milam or GEL, or their respective Affiliates to secure the Obligations. Nothing in this Letter Agreement extinguishes, novates or releases any right, claim, Lien, security interest or entitlement of GEL, Milam or their respective Affiliates created by or contained in the CFC or any of such Contract Documents, nor is Lazarus released from any covenant, warranty or Obligation created by or contained therein.

(e)Lazarus hereby agrees to keep the Equipment in good working order and condition and to use the Equipment exclusively at the Facility and in a manner that a reasonable prudent owner of such Equipment would. Lazarus further agrees to carry customary insurance covering the Equipment. Lazarus shall not remove the Equipment from the Facility without the prior written consent of GEL. The security interests granted in the Contract Documents shall cover the Equipment and Lazarus agrees to execute a financing statement covering the Equipment.

(f)Lazarus agrees and acknowledges that GEL has satisfied all of its obligations under the 2013 Turnaround Letter and that no additional funds will be advanced to Lazarus thereunder.

(g)Lazarus for itself, its successors and assigns and all those at interest therewith (collectively, the "Releasing Parties"), jointly and severally, hereby voluntarily and forever, RELEASE, DISCHARGE AND ACQUIT the Contractor Group (sometimes referred to below collectively as the "Released Parties") and all those at interest therewith of and from any and all Claims or losses of every kind or nature at this time known or unknown, direct or indirect, fixed or contingent, which the Releasing Parties, have or hereafter may have arising out of any act, occurrence, transaction, or omission occurring from the beginning of time to the date of execution of this Letter Agreement if related to the CFC, the other Contract Documents or any of the agreements referenced in the first paragraph above (the "Released Claims"), except that the future duties and obligations of the Contractor Group under the CFC and the Contract Documents shall not be included in the term Released Claims. IT IS THE EXPRESS INTENT OF THE RELEASING PARTIES THAT THE RELEASED CLAIMS SHALL INCLUDE ANY CLAIMS OR CAUSES OF ACTION ARISING FROM OR ATTRIBUTABLE TO THE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY OF THE RELEASED PARTIES.

Section 3. Certain Representations

(a)Each party hereby represents to the other that (a) it has full power and authority to execute and deliver this Letter Agreement and to consummate the transactions contemplated hereby, (b) the execution and delivery of this Letter Agreement by such party have been duly and validly authorized by all necessary corporate action on the part of such party, and (c) this Letter Agreement has been duly and validly executed and delivered by such party and constitutes a valid and binding obligation of such party, enforceable against such party in accordance with its terms, except that such enforceability (i) may be limited by bankruptcy, insolvency, moratorium or other similar laws affecting or relating to the enforcement of creditors' rights generally and (ii) is subject to general principles of equity and the discretion of the court before which any proceedings seeking injunctive relief or specific performance may be brought.

(b)In connection with each advance of funds or direct payment made by GEL or its Affiliates pursuant to this Letter, Lazarus represents, warrants and certifies to GEL that the amounts requested by Lazarus represent the actual costs incurred by Lazarus, after giving effect to all discounts or rebates, for the item for which such payment or advance is requested, and that the item is or will be in exclusive use at the Facility.

As modified by this Letter Agreement, all of the terms of the JMA, CFC, Supply Agreement, Operating Expense Payment Letter Agreements, Acknowledgement Letter, December 2012 Payments Letter Agreement, the Settlement Payment Distribution Letter, and the 2013 Turnaround Letter are hereby ratified and confirmed and shall remain in full force and effect.

[Signature Page Follows.]

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IN WITNESS WHEREOF, the parties hereto have caused this Letter Agreement to be executed by their duly authorized representatives effective as of the date first written above.

GEL TEX MARKETING, LLC, a Delaware limited liability company
By:	/s/ R.V. DEERE
Name:	R.V. Deere
Title:	CFO
MILAM SERVICES, INC., a Delaware corporation
By:	/s/ R.V. DEERE
Name:	R.V. Deere
Title:	CFO
LAZARUS ENERGY LLC, a Delaware limited liability company
By:	/s/ JONATHAN CARROLL
Name:	Jonathan Carroll
Title:	President

3

EXHIBIT A

Petroleum Measurement Equipment Company Invoices

(see attached)

4

EXHIBIT B

Guardian Compliance Invoices

(see attached)

5

EXHIBIT C

Firefighting Equipment Description

Air packs

Foam for rack sprinkler

All call emergency system

Gas monitor

Fire engine/control panel

Cold packs

PPE fire gear

6

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, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		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, 2013	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, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, 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, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		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, 2013 (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 (PrincipalFinancial 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, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

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11. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	September 30,		December 31,
	2013		2012
Refinery and facilities	$	35,696,393	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		559,486		577,567
		38,393,090		36,714,977
Less: Accumulated depletion, depreciation and amortization		2,671,821		1,674,151
		35,721,269		35,040,826
Construction in Progress		187,004		821,259
Property, Plant and Equipment, Net	$	35,908,273	$	35,862,085

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts, USD $)	Sep. 30, 2013	Dec. 31, 2012
Commodity Contracts
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 160,920	$ (136,100)

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUE FROM OPERATIONS
Refined product sales	$ 106,541,284	$ 103,738,982	$ 320,025,559	$ 233,926,241
Pipeline operations	78,909	117,712	229,162	312,098
Oil and gas sales	200	5,785	200	13,067
Total revenue from operations	106,620,393	103,862,479	320,254,921	234,251,406
COST OF OPERATIONS
Cost of refined products sold	105,314,208	96,160,575	317,508,586	229,853,030
Refinery operating expenses	2,629,518	2,559,456	8,099,371	5,862,121
Pipeline operating expenses	40,813	107,534	122,592	344,654
Lease operating expenses	16,797	18,653	58,088	63,612
General and administrative expenses	387,100	442,132	1,333,203	1,702,439
Depletion, depreciation and amortization	337,156	452,142	997,671	1,170,927
Abandonment expense	8	539,996	51,360	539,996
Accretion expense	28,173	29,118	84,513	79,868
Total cost of operations	108,753,773	100,309,606	328,255,384	239,616,647
Income (loss) from operations	(2,133,380)	3,552,873	(8,000,463)	(5,365,241)
OTHER INCOME (EXPENSE)
Net tank rental revenue	278,349	81,365	835,048	256,684
Interest and other income	668	16,439	2,480	20,354
Interest expense	(226,374)	(74,227)	(788,143)	(583,077)
Total other income (expense)	52,643	23,577	49,385	(306,039)
Income (loss) from continuing operations before income taxes	(2,080,737)	3,576,450	(7,951,078)	(5,671,280)
Income tax expense, current	0	(2,503)	0	(15,647)
Income (loss) from continuing operations, net of tax	(2,080,737)	3,573,947	(7,951,078)	(5,686,927)
Loss from discontinued operations, net of tax	0	(4,336,708)	0	(4,443,566)
Net loss	$ (2,080,737)	$ (762,761)	$ (7,951,078)	$ (10,130,493)
Basic income (loss) per common share
Continuing operations	$ (0.20)	$ 0.34	$ (0.76)	$ (0.56)
Discontinued operations	$ 0	$ (0.41)	$ 0	$ (0.43)
Basic loss per common share	$ (0.20)	$ (0.07)	$ (0.76)	$ (0.99)
Diluted income (loss) per common share
Continuing operations	$ (0.20)	$ 0.34	$ (0.76)	$ (0.56)
Discontinued operations	$ 0	$ (0.41)	$ 0	$ (0.43)
Diluted loss per common share	$ (0.20)	$ (0.07)	$ (0.76)	$ (0.99)
Weighted average number of common shares outstanding:
Basic	10,421,731	10,545,690	10,450,906	10,191,980
Diluted	10,421,731	10,545,690	10,450,906	10,191,980

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4. Business Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Business Segment Information

We are engaged in three lines of business: (i) refinery operations, (ii) pipeline transportation and (iii) oil and gas exploration and production. As part of our refinery operations business segment, we also conduct petroleum storage and terminaling operations. Our primary operating asset is the Nixon Facility. We also operate oil and natural gas pipelines in the Gulf of Mexico and hold oil and natural gas leasehold interests in the U.S. Gulf of Mexico; however, these operations are considered non-core to our business. Management uses earnings before interest, income taxes and depreciation ("EBITDA") to assess the operating results and effectiveness of our business segments.

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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	106,541,284		$	78,909		$	200		$	-		$	106,620,393
Operation cost(2)		(107,961,900	)		(93,308	)		(20,797	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(1,142,267	)	$	(14,399	)	$	(20,597	)	$	(340,612	)
Depletion, depreciation and amortization														(337,156	)
Other expense, net														(225,706	)
Loss from continuing operations,													$	(2,080,737	)
before income taxes
Capital expenditures	$	356,889		$	-		$	-		$	-		$	356,889
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the three months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Three Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	103,738,982		$	117,712		$	5,785		$	-		$	103,862,479
Operation cost(2)		(98,755,479	)		(211,114	)		(730,774	)		(160,097	)		(99,857,464	)
Other non-interest income		81,365			-			-			-			81,365
EBITDA	$	5,064,868		$	(93,402	)	$	(724,989	)	$	(160,097	)
Depletion, depreciation and amortization														(452,142	)
Other expense, net														(57,788	)
Income from continuing operations,													$	3,576,450
before income taxes
Loss from discontinued operations													$	(4,336,708	)
Capital expenditures	$	494,312		$	-		$	-		$	-		$	494,312
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable 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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	320,025,559		$	229,162		$	200		$	-		$	320,254,921
Operation cost(2)		(325,625,984	)		(312,209	)		(120,856	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			-			835,048
EBITDA	$	(4,765,377	)	$	(83,047	)	$	(120,656	)	$	(1,198,664	)
Depletion, depreciation and amortization														(997,671	)
Other expense, net														(785,663	)
Loss from continuing operations,													$	(7,951,078	)
before income taxes
Capital expenditures	$	1,244,859		$	-		$	-		$	-		$	1,244,859
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the nine months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Nine Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	233,926,241		$	312,098		$	13,067		$	-		$	234,251,406
Operation cost(2)		(235,987,724	)		(648,334	)		(1,153,146	)		(656,516	)		(238,445,720	)
Other non-interest income		256,684			-			-			-			256,684
EBITDA	$	(1,804,799	)	$	(336,236	)	$	(1,140,079	)	$	(656,516	)
Depletion, depreciation and amortization														(1,170,927	)
Other expense, net														(562,723	)
Loss from continuing operations,													$	(5,671,280	)
before income taxes
Loss from discontinued operations													$	(4,443,566	)
Capital expenditures	$	2,568,449		$	-		$	-		$	-		$	2,568,449
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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18. Leases

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month.  The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis.   For the three months ended September 30, 2013 and 2012, rent expense for the office lease was $25,161 and $26,061, respectively.  For the nine months ended September 30, 2013 and 2012, rent expense for the office lease was $76,382 and $78,182, respectively.

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17. Long-Term Debt (Details Narrative) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery loan accrued interest	$ 37,148
Notre Dame debt accrued interest	1,014,356	858,784
Construction funding accrued interest	617,988	386,695
Capital leases	$ 0	$ 2,119

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8. Prepaid Expenses and Other Current Assets (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 78,848	$ 185,814
Prepaid professional fees	141,500
Employee advances		22,500
Prepaid loan closing fees	33,513	20,000
Unrealized hedging gains	160,920
Prepaid Expenses, Net	$ 414,781	$ 228,314

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12. Discontinued Operations

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Discontinued Operations

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky Langsa, Limited (“Blue Sky”) to dispose of its 7% undivided working interest in Indonesia.  As a result, our operations related to Indonesia ceased effective November 6, 2012 and the disposal was completed on February 28, 2013.  Operations associated with Indonesia, which were previously reported as part of the Oil and Gas Exploration & Production business segment, have been classified as discontinued operations and are presented in a separate line in the consolidated statements of operations for all periods presented.

The following is a summary of the operating results of our discontinued operations:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013		2012
Revenue	$	-	$	231,658		$	-	$	674,797
Lease operating expenses		-		332,809			-		788,525
Depletion, depreciation and amortization		-		45,240			-		124,811
Abandonment expense		-		-			-		-
Impairment expense		-		3,858,427			-		3,858,427
Bad debt expense		-		321,732			-		321,732
Accretion expense		-		10,158			-		24,868
Total costs and expenses		-		4,568,366			-		5,118,363
Loss from discontinued operations, net of tax	$	-	$	(4,336,708	)	$	-	$	(4,443,566	)

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4. Business Segment Information (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues	$ 106,620,393	$ 103,862,479	$ 320,254,921	$ 234,251,406
Operation cost		4,568,366		5,118,363
Depletion, depreciation and amortization		45,240		124,811
Loss from discontinued operations		(4,336,708)		(4,443,566)
Crude Oil and Condensate Processing [Member]
Revenues	106,541,284	103,738,982	320,025,559	233,926,241
Operation cost	(107,961,900)	(98,755,479)	(325,625,984)	(235,987,724)
Other non-interest income	278,349	81,365	835,048	256,684
EBITDA	(1,142,267)	5,064,868	(4,765,377)	(1,804,799)
Capital expenditures	356,889	494,312	1,244,859	2,568,449
Identifiable assets	48,925,380	48,645,278	48,925,380	48,645,278
Segment Pipeline Transportation [Member]
Revenues	78,909	117,712	229,162	312,098
Operation cost	(93,308)	(211,114)	(312,209)	(648,334)
Other non-interest income
EBITDA	(14,399)	(93,402)	(83,047)	(336,236)
Capital expenditures
Identifiable assets	1,564,180	11,350,264	1,564,180	11,350,264
Oil And Gas Exploration and Production
Revenues	200	5,785	200	13,067
Operation cost	(20,797)	(730,774)	(120,856)	(1,153,146)
Other non-interest income
EBITDA	(20,597)	(724,989)	(120,656)	(1,140,079)
Capital expenditures
Identifiable assets	4,825	812,229	4,825	812,229
Corporate and Other
Revenues
Operation cost	(340,612)	(160,097)	(1,198,664)	(656,516)
Other non-interest income
EBITDA	(340,612)	(160,097)	(1,198,664)	(656,516)
Capital expenditures
Identifiable assets	844,334	1,010,097	844,334	1,010,097
Total
Revenues	106,620,393	103,862,479	320,254,921	234,251,406
Operation cost	(108,416,617)	(99,857,464)	(327,257,713)	(238,445,720)
Other non-interest income	278,349	81,365	835,048	256,684
Depletion, depreciation and amortization	(337,156)	(452,142)	(997,671)	(1,170,927)
Other expense, net	(225,706)	(57,788)	(785,663)	(562,723)
Income (loss) before taxes	(2,080,737)	3,576,450	(7,951,078)	(5,671,280)
Loss from discontinued operations		(4,336,708)		(4,443,566)
Capital expenditures	356,889	494,312	1,244,859	2,568,449
Identifiable assets	$ 51,338,719	$ 61,817,868	$ 51,338,719	$ 61,817,868

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9. Deposits (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Deposits Details
Utility deposits	$ 27,250	$ 36,500
Equipment deposits	124,526	124,526
Tax bonds	792,000	792,000
Purchase option deposits	283,421	283,421
Rent deposits	9,463
Deposits	$ 1,236,660	$ 1,236,447

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10. Inventories (Tables)

9 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventories balances

	September 30,		December 31,
	2013		2012
Low-sulfur diesel	$	399,869	$	397,240
Naphtha		1,450,931		1,562,055
Jet fuel		1,715,129		-
Atmospheric gas oil		801,691		322,356
Crude		19,041		19,041
	$	4,386,661	$	2,300,692

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21. Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Management Agreement

See “Note (13) Accounts Payable, Related Party” of this report for additional disclosures related to the Management 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. 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.

● 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 has continued to make 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 of LE (as defined below) 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.   The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and 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 the agreement between LE and GEL pursuant to which the parties will 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 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 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 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 obligation 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.

As of September 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $10,896,196.  As of September 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $7,253,059.

Lazarus Texas Refinery I, LLC (“LTRI”) Option

In June 2012, we purchased an exclusive option, which expires on December 31, 2013, from LEH to acquire all of the issued and outstanding membership interests of LTRI, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.

In the event we exercise the option to purchase the Ingleside Refinery, Blue Dolphin and LEH will enter into a definitive purchase and sale agreement. We paid LEH a fully refundable sum of $100,000 in cash as consideration to purchase the exclusive option.  Upon exercise of the exclusive option to purchase the Ingleside Refinery, we will assume all outstanding liabilities, including a note payable, and reimburse LEH for costs associated with the acquisition, refurbishment and environmental remediation of the site.  The parties continue to monitor such refurbishment and remediation efforts as a prerequisite to determining the purchase price. If there is a material difference between LEH’s expenditures for such remediation efforts and our desired purchase price, LEH has agreed to refund us the purchase price for the Ingleside Refinery option.

Lazarus Energy Development, LLC (“LED”) Option

In connection with the Merger, we purchased an exclusive option, which expires on December 31, 2013, from LEH to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option.

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 will have a material adverse effect on our results of operations.

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 diesel and other fuels; 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 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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20. Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

LE is a limited liability company and, prior to the Merger, its 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. Upon the Merger, LE became the subsidiary of Blue Dolphin and LE’s taxable income or NOLs flowed through to Blue Dolphin for federal and state income tax purposes.  However, Section 382 of the Internal Revenue Code imposes a limitation on Blue Dolphin’s use of LE’s NOLs.  The amount of NOLs subject to such limitations is approximately $18.8 million. Nevertheless, the NOLs generated subsequent to the Merger, approximately $14.7 million, is not subject to any such limitation. For the three and nine months ended September 30, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended September 30, 2013 and 2012, income tax expense was $0 and $2,503, respectively.  For the nine months ended September 30, 2013 and 2012, income tax expense was $0 and $15,647, respectively.  Income tax expense and benefit related to the State of Texas margins tax (“TMT”).  TMT 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.

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23. Stock Options (Tables)

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock options activity table

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at September 30, 2013		14,642	$	19.67		0.1	$	-
Options exercisable at September 30, 2013		14,642	$	19.67		0.1	$	-

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6. Refined Products Inventory Risk Management (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -
net short (long) positions		45,000		-		-		-

Fair value amounts of derivative instruments

		September 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	160,920	$	(136,100	)

Effect of derivative instruments

		Gain (Loss) Recognized
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives	Statements of Operation Location	2013			2012			2013			2012
Commodity contracts	Cost of refined products sold	$	(297,179	)	$	(177,201	)	$	(330,320	)	$	(305,785	)

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12. Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2013

Discontinued Operations Tables

Operating results of discontinued operations

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013		2012
Revenue	$	-	$	231,658		$	-	$	674,797
Lease operating expenses		-		332,809			-		788,525
Depletion, depreciation and amortization		-		45,240			-		124,811
Abandonment expense		-		-			-		-
Impairment expense		-		3,858,427			-		3,858,427
Bad debt expense		-		321,732			-		321,732
Accretion expense		-		10,158			-		24,868
Total costs and expenses		-		4,568,366			-		5,118,363
Loss from discontinued operations, net of tax	$	-	$	(4,336,708	)	$	-	$	(4,443,566	)

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4. Business Segment Information (Details Narrative) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013
Segment Reporting [Abstract]
Amortization expense	$ 143,645	$ 143,645
Cost of refined products sold realized loss	378,899	627,340
Cost of refined products sold unrealized gain	$ 81,720	$ 297,020

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3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2013

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”). The 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.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (12) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

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 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 $314,812 and $420,896 at September 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,383 and $89,593 at September 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments

Accounts Receivable, Allowance for Doubtful Accounts and Concentrations 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 receivables for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit 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 balances of $59,852 and $170,896 at September 30, 2013 and December 31, 2012, respectively.

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, 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.

For the three months ended September 30, 2012, we had 3 customers that accounted for approximately 81% of our refined petroleum product sales.  These 3 customers represented approximately $4.9 million in accounts receivable at September 30, 2012.  For the nine months ended September 30, 2012, we had 4 customers that accounted for approximately 83% of our refined petroleum product sales.  These 4 customers represented approximately $6.0 million in accounts receivable at September 30, 2012.

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 Energy, LLC (“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 condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed 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 charged to expense as incurred. Management expects to continue making improvements to our refinery assets 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, 2013 and 2012.

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, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets in 2012, 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.

Intangibles - Goodwill and Other

Goodwill. We recognized goodwill in connection with our reverse merger with LE. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with FASB ASC guidance related to intangibles, goodwill and other. We perform an impairment test annually in the fourth quarter.

Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.

In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment,” in connection with the performance of our annual goodwill impairment testing. Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.

The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill during the fourth quarter of 2012.  The impairment recognized during 2012 represented 100% of goodwill.

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE. 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, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2012.

Debt Issue Costs

We have debt issue costs related to certain of our 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 $506,985 and $532,335 at September 30, 2013 and December 31, 2012, respectively.  Accumulated amortization was $168,995 and $143,645 at September 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note.  For the three and nine months ended September 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  For the three and nine months ended September 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  See “Note (14) Notes Payable” and “Note (17) 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 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 Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at September 30, 2013 was not material.

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 (20) Income Taxes” for further details.

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 comparison of 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 asset retirement obligation 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 a quarterly 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 transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold 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 the unaudited consolidated statement 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 stock 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. For periods in which we have a net loss, we exclude stock options because their effect would be anti-dilutive.

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 the consolidated statement of income 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 condensed 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 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 assets acquired, including identifiable intangibles 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

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation.

New Pronouncements Issued but Not Yet Effective

We have evaluated recent accounting pronouncements that are not yet effective and determined that they do not have a material impact on our consolidated financial statements or disclosures.

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16. Asset Retirement Obligations (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Asset Retirement Obligations Details
Fair value of asset retirement obligations at December 31, 2012			$ 921,260
Liabilities settled			(8,243)
Accretion expense	28,173	29,118	84,513	79,868
Asset retirement obligations as of September 30, 2013	997,530		997,530
Less current portion of asset retirement obligations	88,044		88,044		0
Asset retirement obligations, long-term balance at September 30, 2013	$ 909,486		$ 909,486		$ 921,260

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22. Earnings per share (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share [Abstract]
Income (loss) from continuing operations, net of tax	$ (2,080,737)	$ 3,573,947	$ (7,951,078)	$ (5,686,927)
Loss from discontinued operations, net of tax		(4,336,708)		(4,443,566)
Net income (loss)	$ (2,080,737)	$ (762,761)	$ (7,951,078)	$ (10,130,493)
Basic and diluted earnings (loss) per common share
Continuing operations	$ (0.20)	$ 0.34	$ (0.76)	$ (0.56)
Discontinued operations	$ 0	$ (0.41)	$ 0	$ (0.43)
Basic and diluted earnings (loss) per common share	$ (0.20)	$ (0.07)	$ (0.76)	$ (0.99)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,421,731	10,545,690	10,450,906	10,191,980

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15. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Accrued Expenses And Other Current Liabilities Details
Excise taxes	$ 764,749	$ 292,303
Transportation		69,551
Other payable	238,902	134,501
Property taxes	40,500
Unrealized hedging loss		136,100
Unearned revenue		92,783
Accrued Expenses and Other Current Liabilities, Net	$ 1,044,151	$ 725,238

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16. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Asset retirment obligations at December 31, 2012	$	921,260
Liabilities settled		(8,243	)
Accretion expense		84,513
		997,530
Less:  current portion of asset retirement obligations		88,044
Asset retirement obligations, long-term balance
at September 30, 2013	$	909,486

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19. Treasury Stock (Details Narrative)	Sep. 30, 2013
Treasury Stock Details Narrative
Treasury stock	150,000

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19. Treasury Stock

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia.  The non-cash transaction was completed on February 28, 2013.  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. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  As of September 30, 2013, there were 150,000 shares of treasury stock.

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Condensed Consolidated Statements of Cash Flows (Parenthetical) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Statement of Cash Flows [Abstract]
Cash acquired from business acquisition	$ 1,674,594	$ 1,674,594

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2. Basis of Presentation

9 Months Ended

Sep. 30, 2013

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”). The 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.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (12) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

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5. Fair Value Measurement

9 Months Ended

Sep. 30, 2013

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 books and 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, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at September 30, 2013 and December 31, 2012 was $21,348,742 and $15,850,418, respectively. Accrued interest associated with our long-term debt and short-term notes payable at September 30, 2013 and December 31, 2012 was $1,670,188 and $1,499,136, respectively.  The following table represents our assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and the basis for that measurement:

	Fair Value Measurement at September 30, 2013 Using
Financial assets:	Carrying Value as at September 30, 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	$	160,920	$	160,920	$	-	$	-

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

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23. Stock Options (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Shares
Options outstanding at December 31, 2012	14,642
Options granted
Options exercised
Options expired or cancelled
Options outstanding at September 30, 2013	14,642
Weighted Average Exercise Price
Options granted
Options exercised
Options expired or cancelled
Options outstanding at September 30, 2013	$ 19.67
Options exercisable at September 30, 2013	$ 19.67
Weighted Average Remaining Contractual Life
Options outstanding at September 30, 2013	1 month 6 days
Options exercisable at at September 30, 2013	1 month 6 days
Aggregate Intrinisic Value
Options outstanding at at September 30, 2013
Options exercisable at at September 30, 2013

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3. Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

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. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the 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 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 $314,812 and $420,896 at September 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,383 and $89,593 at September 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments

Accounts Receivable, Allowance for Doubtful Accounts and Concentrations 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 receivables for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit 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 balances of $59,852 and $170,896 at September 30, 2013 and December 31, 2012, respectively.

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, 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.

For the three months ended September 30, 2012, we had 3 customers that accounted for approximately 81% of our refined petroleum product sales.  These 3 customers represented approximately $4.9 million in accounts receivable at September 30, 2012.  For the nine months ended September 30, 2012, we had 4 customers that accounted for approximately 83% of our refined petroleum product sales.  These 4 customers represented approximately $6.0 million in accounts receivable at September 30, 2012.

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 Energy, LLC (“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 condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed 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 charged to expense as incurred. Management expects to continue making improvements to our refinery assets 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, 2013 and 2012.

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, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets in 2012, 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.

Intangibles – Goodwill and Other

Goodwill. We recognized goodwill in connection with our reverse merger with LE. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with FASB ASC guidance related to intangibles, goodwill and other. We perform an impairment test annually in the fourth quarter.

Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.

In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment,” in connection with the performance of our annual goodwill impairment testing. Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.

The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill during the fourth quarter of 2012.  The impairment recognized during 2012 represented 100% of goodwill.

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE. 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, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2012.

Debt Issue Costs

We have debt issue costs related to certain of our 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 $506,985 and $532,335 at September 30, 2013 and December 31, 2012, respectively.  Accumulated amortization was $168,995 and $143,645 at September 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note.  For the three and nine months ended September 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  For the three and nine months ended September 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $25,349, respectively.  See “Note (14) Notes Payable” and “Note (17) 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 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 Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at September 30, 2013 was not material.

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 (20) Income Taxes” for further details.

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 comparison of 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 asset retirement obligation 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 a quarterly 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 transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold 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 the unaudited consolidated statement 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 stock 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. For periods in which we have a net loss, we exclude stock options because their effect would be anti-dilutive.

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 the consolidated statement of income 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 condensed 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 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 assets acquired, including identifiable intangibles 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

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation.

New Pronouncements Issued but Not Yet Effective

We have evaluated recent accounting pronouncements that are not yet effective and determined that they do not have a material impact on our consolidated financial statements or disclosures.

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14. Note Payable (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Notes payable

	September 30,		December 31,
	2013		2012
Short-Term Note for Financing Costs	$	23,188	$	39,866
Short-Term Captial Leases		7,056		4,075
	$	30,244	$	43,941

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22. Earnings Per Share

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

The following table provides reconciliation between basic and diluted loss per share on a continuing and discontinued operations basis:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Income (loss) from continuing operations, net of tax	$	(2,080,737	)	$	3,573,947		$	(7,951,078	)	$	(5,686,927	)
Loss from discontinued operations, net of tax		-			(4,336,708	)		-			(4,443,566	)
Net loss		(2,080,737	)		(762,761	)		(7,951,078	)		(10,130,493	)
Basic and diluted gain (loss) per common share
Continuing operations	$	(0.20	)	$	0.34		$	(0.76	)	$	(0.56	)
Discontinued operations	$	-		$	(0.41	)	$	-		$	(0.43	)
Basic and diluted loss per common share	$	(0.20	)	$	(0.07	)	$	(0.76	)	$	(0.99	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,731			10,545,690			10,450,906			10,191,980

Diluted EPS is computed by dividing net loss available to common stockholders by the weighted average number of shares of common stock outstanding.  For the three months ended September 30, 2012, none of the stock options outstanding under our 2000 Stock Incentive Plan ("the "Plan") were included in the computation of diluted earnings per share because the option exercise price was greater than the average market price of the common stock. Diluted EPS for the three and nine months ended September 30, 2013 and the nine months ended September 30, 2012 excludes stock options outstanding as they would be anti-dilutive.

For the three months ended September 30, 2012, the weighted average number of shares of common stock outstanding was computed as LE’s number of shares of common stock outstanding from January 1, 2012 to February 15, 2012 (the beginning of the period to the date of LE’s acquisition by Blue Dolphin) combined with Blue Dolphin’s number of shares of common stock outstanding from February 15, 2012 to September 30, 2012 (the date of LE’s acquisition by Blue Dolphin to the end of the period).  For the period prior to the date of LE’s acquisition by Blue Dolphin, LE’s number of shares of common stock was computed as LE’s one member unit prior to the acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

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4. Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Business segment reporting

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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	106,541,284		$	78,909		$	200		$	-		$	106,620,393
Operation cost(2)		(107,961,900	)		(93,308	)		(20,797	)		(340,612	)		(108,416,617	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(1,142,267	)	$	(14,399	)	$	(20,597	)	$	(340,612	)
Depletion, depreciation and amortization														(337,156	)
Other expense, net														(225,706	)
Loss from continuing operations,													$	(2,080,737	)
before income taxes
Capital expenditures	$	356,889		$	-		$	-		$	-		$	356,889
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $378,899 and an unrealized gain of $81,720.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the three months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Three Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	103,738,982		$	117,712		$	5,785		$	-		$	103,862,479
Operation cost(2)		(98,755,479	)		(211,114	)		(730,774	)		(160,097	)		(99,857,464	)
Other non-interest income		81,365			-			-			-			81,365
EBITDA	$	5,064,868		$	(93,402	)	$	(724,989	)	$	(160,097	)
Depletion, depreciation and amortization														(452,142	)
Other expense, net														(57,788	)
Income from continuing operations,													$	3,576,450
before income taxes
Loss from discontinued operations													$	(4,336,708	)
Capital expenditures	$	494,312		$	-		$	-		$	-		$	494,312
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable 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
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	320,025,559		$	229,162		$	200		$	-		$	320,254,921
Operation cost(2)		(325,625,984	)		(312,209	)		(120,856	)		(1,198,664	)		(327,257,713	)
Other non-interest income		835,048			-			-			-			835,048
EBITDA	$	(4,765,377	)	$	(83,047	)	$	(120,656	)	$	(1,198,664	)
Depletion, depreciation and amortization														(997,671	)
Other expense, net														(785,663	)
Loss from continuing operations,													$	(7,951,078	)
before income taxes
Capital expenditures	$	1,244,859		$	-		$	-		$	-		$	1,244,859
Identifiable assets(3)	$	48,925,380		$	1,564,180		$	4,825		$	844,334		$	51,338,719

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $627,340 and an unrealized gain of $297,020.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the nine months ended September 30, 2012 (and at September 30, 2012) were as follows:

	Nine Months Ended September 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	233,926,241		$	312,098		$	13,067		$	-		$	234,251,406
Operation cost(2)		(235,987,724	)		(648,334	)		(1,153,146	)		(656,516	)		(238,445,720	)
Other non-interest income		256,684			-			-			-			256,684
EBITDA	$	(1,804,799	)	$	(336,236	)	$	(1,140,079	)	$	(656,516	)
Depletion, depreciation and amortization														(1,170,927	)
Other expense, net														(562,723	)
Loss from continuing operations,													$	(5,671,280	)
before income taxes
Loss from discontinued operations													$	(4,443,566	)
Capital expenditures	$	2,568,449		$	-		$	-		$	-		$	2,568,449
Identifiable assets(3)	$	48,645,278		$	11,350,264		$	812,229		$	1,010,097		$	61,817,868

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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21. Commitments and Contingencies (Details Narrative) (USD $)	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Advances and Deficit Amounts	$ 10,896,196
Deficit Amount under the Construction and Funding Agreement	$ 7,253,059

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9. Deposits (Tables)

9 Months Ended

Sep. 30, 2013

Deposits Tables

Deposit balances

	September 30,		December 31,
	2013		2012
Utility deposits	$	27,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,236,660	$	1,236,447

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20. Income Taxes (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Taxes Details Narrative
Income tax expense	$ 0	$ 2,503	$ 0	$ 15,647

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7. Concentration of Risk (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Concentration Risk	1.00%	100.00%	100.00%	100.00%
Low-sulfur diesel
Concentration Risk	44.90%	49.70%	48.20%	47.40%
Naphtha
Concentration Risk	24.30%	25.40%	25.60%	26.20%
Atmospheric gas oil
Concentration Risk	2.60%	24.90%	24.50%	26.10%
Reduced crude [Member]
Concentration Risk	0.00%	0.00%	1.00%	3.00%
Jet Fuel [Member]
Concentration Risk	48.00%	0.00%	16.00%	0.00%

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5. Fair Value Measurement (Details) (USD $)	Sep. 30, 2013
Financial liabilties:
Commodity contracts	$ 160,920
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	160,920
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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22. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings per share

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Income (loss) from continuing operations, net of tax	$	(2,080,737	)	$	3,573,947		$	(7,951,078	)	$	(5,686,927	)
Loss from discontinued operations, net of tax		-			(4,336,708	)		-			(4,443,566	)
Net loss		(2,080,737	)		(762,761	)		(7,951,078	)		(10,130,493	)
Basic and diluted gain (loss) per common share
Continuing operations	$	(0.20	)	$	0.34		$	(0.76	)	$	(0.56	)
Discontinued operations	$	-		$	(0.41	)	$	-		$	(0.43	)
Basic and diluted loss per common share	$	(0.20	)	$	(0.07	)	$	(0.76	)	$	(0.99	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,731			10,545,690			10,450,906			10,191,980

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,580,973	10,563,297
Common stock, shares outstanding	10,580,973	10,563,297

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8. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 2013

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	September 30,		December 31,
	2013		2012
Prepaid insurance	$	78,848	$	185,814
Prepaid professional fees		141,500		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		160,920		-
	$	414,781	$	228,314

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
OPERATING ACTIVITIES
Net loss	$ (7,951,078)	$ (10,130,493)
Loss from discontinued operations	0	4,443,566
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	997,671	1,162,362
Impairment of oil and gas properties		3,858,427
Unrealized gain on derivatives	(297,020)	(21,470)
Amortization of debt issue costs	25,350	25,349
Amortization of intangible assets	9,463	8,565
Accretion expense	84,513	79,868
Abandonment costs incurred	51,360	(141,099)
Common stock issued for services	100,000	119,000
Bad debt expense	0	321,732
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash	62,210	(810)
Accounts receivable	6,358,937	(7,852,717)
Prepaid expenses and other current assets	(186,467)	119,529
Deposits	(213)	(763,421)
Inventory	(2,085,969)	(312,766)
Accounts payable, accrued expenses and other liabilities	(3,395,086)	8,057,321
Accounts payable, related party	1,665,782	2,275,665
Net cash provided by (used in) operating activities - continuing operations	(4,560,547)	1,248,608
Net cash used in operating activities - discontinued operations	0	(4,293,887)
Net cash used in operating activities	(4,560,547)	(3,045,279)
INVESTING ACTIVITIES
Capital expenditures	(1,244,859)	(2,568,449)
Proceeds from sale of assets	201,000	0
Cash acquired on Acquisition	0	(1,674,594)
Net cash provided by (used in) investing activities	(1,043,859)	(893,855)
FINANCING ACTIVITIES
Proceeds from issuance of debt	5,750,611	4,788,623
Payments on long term debt	(60,876)	(713,686)
Proceeds from notes payable	15,032	24,548
Payments on notes payable	(206,445)	(22,900)
Net cash provided by financing activities	5,498,322	4,076,585
Net increase (decrease) in cash and cash equivalents	(106,084)	137,451
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	420,896	1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	314,812	139,273
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	800,000	0
Non-cash investing and financing activities:
Financing of insurance premiums	0	82,560
Related party payable converted to equity	0	993,732
Acquisition of Blue Dolphin at fair value, inclusive of cash acquired of $1,674,594	0	18,046,154
Accrued services payable converted to common stock	$ 100,000	$ 119,000

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10. Inventories (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 399,869	$ 397,240
Naphtha	1,450,931	1,562,055
Jet fuel	1,715,129
Atmospheric gas oil	801,691	322,356
Crude	19,041	19,041
Inventories, Net	$ 4,386,661	$ 2,300,692

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 314,812	$ 420,896
Restricted cash	27,383	89,593
Accounts receivable	8,239,818	15,398,755
Prepaid expenses and other current assets	414,781	228,314
Deposits	1,236,660	1,236,447
Inventory	4,386,661	2,300,692
Total current assets	14,620,115	19,674,697
Total property and equipment, net	35,908,273	35,862,085
Debt issue costs, net	506,985	532,335
Other assets	0	9,463
Trade name	303,346	303,346
TOTAL ASSETS	51,338,719	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	15,048,520	19,171,013
Accounts payable, related party	3,259,803	1,594,021
Note payable	30,244	43,941
Asset retirement obligations, current portion	88,044	0
Accrued expenses and other current liabilities	1,044,151	725,238
Interest payable, current portion	655,832	640,352
Long-term debt, current portion	20,018,498	1,816,960
Total current liabilities	40,145,092	23,991,525
Asset retirement obligations, net of current portion	909,486	921,260
Long term debt, net of current portion	1,300,000	13,989,517
Long term interest payable, net of current portion	1,014,356	858,784
Total long-term liabilities	3,223,842	15,769,561
TOTAL LIABILITIES	43,368,934	39,761,086
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,580,973 and 10,563,297 shares issued at September 30, 2013 and December 31, 2012, respectively)	105,810	105,633
Additional paid-in capital	36,623,965	36,524,142
Accumulated deficit	(27,959,990)	(20,008,935)
Treasury stock, 150,000 and 0 shares, respectively, at cost	(800,000)	0
Total stockholders' equity	7,969,785	16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 51,338,719	$ 56,381,926

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5. Fair Value Measurement (Details Narrative) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value Measurement Details Narrative
Fair value of longer term debt	$ 21,348,742	$ 15,850,418
Accrued interest	$ 1,670,188	$ 1,499,136

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23. Stock Options

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Options

The Plan offers incentive awards to employees, including officers (whether or not they are directors), consultants and non-employee directors. The Plan was initially established by the Blue Dolphin Board on April 14, 2000 and approved by Blue Dolphin’s stockholders on May 18, 2000. The Plan was amended effective March 19, 2003 and ratified by Blue Dolphin’s stockholders on May 21, 2003 to increase the common stock available for issuance under the Plan from 500,000 shares to 650,000 shares (Amendment No. 1). The Plan was further amended effective April 5, 2007 and ratified by Blue Dolphin’s stockholders effective May 30, 2007 to increase the common stock available for issuance under the Plan from 650,000 shares to 1,200,000 shares (Amendment No. 2). Effective July 16, 2010, Blue Dolphin’s stockholders approved a 1-for-7 reverse-stock-split of its common stock, which reduced the number of shares of common stock available for issuance under the Plan from 1,200,000 shares to 171,128 shares (Amendment No. 3). Effective January 27, 2012, Blue Dolphin’s stockholders approved an amendment to the Plan to change the expiration date of the Plan from 10 to 20 years (to April 14, 2020), as well as increase the aggregate number of common stock available for issuance under the Plan from 171,128 shares to 1,000,000 shares (Amendment No. 4).  The Compensation Committee of the Board approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

Options granted under the Plan have contractual terms from 6 to 10 years. The exercise price of incentive stock options cannot be less than 100% of the fair market value of a share of our common stock determined on the grant date. Although the Plan provides for the granting of other incentive awards, only incentive stock options and non-statutory stock options have been issued under the Plan to date. The Plan is administered by the Compensation Committee of the Board.

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the three and nine months ended September 30, 2013.

At September 30, 2013, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at September 30, 2013		14,642	$	19.67		0.1	$	-
Options exercisable at September 30, 2013		14,642	$	19.67		0.1	$	-

We recognized no compensation expense for vested stock options for the three and six months ended September 30, 2013 and 2012. As of September 30, 2013, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the three months ended September 30, 2013 and 2012, we recognized $50,000 and $0, respectively, of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.  For the nine months ended September 30, 2013 and 2012, we recognized $100,000 and $60,000, respectively, of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

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17. Long-Term Debt

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Long-Term Debt

Our long-term debt consists of notes payable, construction financing and capital leases, as follows:

	September 30,		December 31,
	2013		2012
Refinery Note	$	9,122,302	$	9,298,183
Construction and Funding Agreement		10,896,196		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		-		2,119
		21,318,498		15,806,477
Less: Current portion of long-term debt		20,018,498		1,816,960
	$	1,300,000	$	13,989,517

Refinery Note.  The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at September 30, 2013) 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 $9,122,302 and $9,298,183 at September 30, 2013 and December 31, 2012, respectively.  Interest was accrued on the Refinery Note in the amount of $37,148 and $250,070 at September 30, 2013 and December 31, 2012, respectively. See "Note (1) Organization- Operating Risks"of this report for additional disclosures related to the Refinery Note.

The Loan Agreement has two financial covenants relating to a current ratio and debt to worth. As of September 30, 2013, we were in violation of these covenants. Accordingly, the Refinery Note was included in the current portion of long-term debt on the condensed consolidated balance sheet as of September 30, 2013.

In October 2011, the Refinery Loan Documents were acquired by American First National Bank (“AFNB”).  On June 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.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  The principal balance outstanding on the Construction and Funding Agreement was $10,896,196 and $5,206,175 at September 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $617,988 and $386,695 at September 30, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with this obligation.

A covenant violation in the Loan Agreement, if not cured or waived, could potentially lead to the termination of the Construction and Funding Agreement. Accordingly, the principal balance outstanding on the Construction and Funding Agreement was included in the current portion of long-term debt on the consolidated balance sheet as of September 30, 2013.

See “Note (21) Commitments and Contingencies” and “Note (24) Subsequent Events” of this report for additional disclosures related to amendments and/or modifications to the Crude Supply Agreement, Construction and Funding Agreement and Joint Marketing Agreement.

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, 2013 and December 31, 2012.  Interest was accrued on the Notre Dame Debt in the amount of $1,014,356 and $858,784 at September 30, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with the Notre Dame Debt.

Pursuant to an Intercreditor and Subordination Agreement dated September 29, 2008, 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.

Pursuant to an Intercreditor and Subordination Agreement dated 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 Milam under the Construction and Funding Agreement.

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 the final maturity became July 1, 2015.

Capital Leases.  Capital lease obligations previously classified as long-term debt were reclassified to short-term notes payable in 2013 as they mature in February 2014.  Long-term capital lease obligations totaled $0 and $2,119 at September 30, 2013 and December 31, 2012.

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17. Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Long Term Debt

	September 30,		December 31,
	2013		2012
Refinery Note	$	9,122,302	$	9,298,183
Construction and Funding Agreement		10,896,196		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Capital Leases		-		2,119
		21,318,498		15,806,477
Less: Current portion of long-term debt		20,018,498		1,816,960
	$	1,300,000	$	13,989,517

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 2) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Commodity Contracts	Sep. 30, 2012 Commodity Contracts
Cost of refined products sold	$ (297,179)	$ (177,201)	$ (330,320)	$ (305,785)

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16. Asset Retirement Obligations (Details Narrative) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
Asset Retirement Obligations Details Narrative
Abandonment expense	$ 8	$ 51,360	$ (141,099)

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

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Property and equipment

	September 30,		December 31,
	2013		2012
Refinery and facilities	$	35,696,393	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		559,486		577,567
		38,393,090		36,714,977
Less: Accumulated depletion, depreciation and amortization		2,671,821		1,674,151
		35,721,269		35,040,826
Construction in Progress		187,004		821,259
Property, Plant and Equipment, Net	$	35,908,273	$	35,862,085

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7. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 2013

Concentration Of Risk Tables

Percentages of all refined petroleum products sales to total sales

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Low-sulfur diesel		44.9	%		49.7	%		48.2	%		47.4	%
Naphtha		24.3	%		25.4	%		25.6	%		26.2	%
Atmospheric gas oil		26.0	%		24.9	%		24.5	%		26.1	%
Reduced crude		0.0	%		0.0	%		0.1	%		0.3	%
Jet fuel		4.8	%		0.0	%		1.6	%		0.0	%
		100.0	%		100.0	%		100.0	%		100.0	%

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8. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2013

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid balances consisted of the following:

	September 30,		December 31,
	2013		2012
Prepaid insurance	$	78,848	$	185,814
Prepaid professional fees		141,500		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		160,920		-
	$	414,781	$	228,314

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7. Concentration of Risk

9 Months Ended

Sep. 30, 2013

Risks and Uncertainties [Abstract]

Concentration of Risk

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2019.

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 in place with most of our customers. 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.

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,
	2013			2012			2013			2012
Low-sulfur diesel		44.9	%		49.7	%		48.2	%		47.4	%
Naphtha		24.3	%		25.4	%		25.6	%		26.2	%
Atmospheric gas oil		26.0	%		24.9	%		24.5	%		26.1	%
Reduced crude		0.0	%		0.0	%		0.1	%		0.3	%
Jet fuel		4.8	%		0.0	%		1.6	%		0.0	%
		100.0	%		100.0	%		100.0	%		100.0	%

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable product.  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.

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14. Note Payable (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Short-Term Note for Financing Costs	$ 23,188	$ 39,866
Short-Term Captial Leases	7,056	4,075
Note Payable,Total	$ 30,244	$ 43,941

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24. Subsequent Events

9 Months Ended

Sep. 30, 2013

Subsequent Events [Abstract]

24. Subsequent Events

On October 30, 2013, LE entered into the October 2013 Letter Agreement with GEL and Milam, effective October 24, 2013.  The October 2013 Letter Agreement modified certain terms of the Crude Supply Agreement, the Construction and Funding Agreement (as amended, restated or supplemented from time to time), and the Joint Marketing Agreement (as amended, restated or supplemented from time to time).

In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and the Joint Marketing Agreement, and GEL agreed to automatically renew the Crude Supply Agreement and the Joint Marketing Agreement at the end of their respective initial terms for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.  In addition, GEL agreed to advance monies to LE 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.

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15. Accrued Expenses and Other Current Liabilities (Tables)

9 Months Ended

Sep. 30, 2013

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

	September 30,		December 31,
	2013		2012
Excise taxes	$	764,749	$	292,303
Transportation		-		69,551
Other payable		238,902		134,501
Property taxes		40,500		-
Unrealized hedging loss		-		136,100
Unearned revenue		-		92,783
	$	1,044,151	$	725,238

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10. Inventories

9 Months Ended

Sep. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventory balances consisted of the following:

	September 30,		December 31,
	2013		2012
Low-sulfur diesel	$	399,869	$	397,240
Naphtha		1,450,931		1,562,055
Jet fuel		1,715,129		-
Atmospheric gas oil		801,691		322,356
Crude		19,041		19,041
	$	4,386,661	$	2,300,692

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable product.  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.

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23. Stock Options (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Issuance of restricted common stock expense			$ 14,642
Expense related to the fair value issuance of restricted common stock	$ 50,000	$ 0	$ 100,000	$ 60,000

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management

9 Months Ended

Sep. 30, 2013

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 the consolidated balance sheets and the related net gain or loss is recorded within cost of refined petroleum products sold in the 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 their 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, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -
net short (long) positions		45,000		-		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in the consolidated balance sheets at September 30, 2013 and December 31, 2012: 

		September 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	160,920	$	(136,100	)

The following table provides the effect of derivative instruments on the consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012: 

		Gain (Loss) Recognized
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives	Statements of Operation Location	2013			2012			2013			2012
Commodity contracts	Cost of refined products sold	$	(297,179	)	$	(177,201	)	$	(330,320	)	$	(305,785	)

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1. Organization

9 Months Ended

Sep. 30, 2013

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 asset is a fifty-six (56) acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (4) Business Segment Information” 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);

●   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 $314,812 and $420,896 at September 30, 2013 and December 31, 2012, respectively.  We have incurred recurring losses from operations and continue to experience a working capital deficit and negative cash flows from operations. We are currently in violation of debt to worth and current ratio covenants in a loan agreement dated September 29, 2008 (the “Loan Agreement”) between LE and 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”). We are currently making our scheduled payments in accordance with the terms and conditions of the Refinery Note and seeking a waiver for the financial ratio covenants.  The lender has not declared an event of default of the Refinery Note. See “Note (17) 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 by and between LE and GEL TEX Marketing, LLC, an affiliate of Genesis (“GEL”), dated August 12, 2011 (the “Joint Marketing Agreement”), and Lazarus Energy Holdings, LLC (“LEH”) 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 GEL and/or LEH will continue to fund our working capital requirements.  In the event our working capital requirements are not funded by our profit share, GEL and/or LEH, we may experience a significant and material adverse effect on our operations.

We believe that our operational strategy, including our recent production of jet fuel and the refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility, 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 that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.  See “Item 1A. Risk Factors” in our previously filed Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”) and “Part II, Item 1A. Risk Factors” in our previously filed Quarterly Reports on Form 10-Q for the three months ended March 31, 2013 and the three months ended June 30, 2013 for risk factors related to working capital and liquidity.

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Sep. 30, 2013
Refined products - net short (long) positions
Volume in Thousands of barrels
Notional Contract Volumes 2013	45,000
Notional Contract Volumes 2014
Notional Contract Volumes 2015
Notional Contract Volumes 2016

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3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Accounting Policies [Abstract]
Restricted cash	$ 27,383		$ 27,383		$ 89,593
Perecentage of revenue from major customers	91.00%	81.00%	92.00%	83.00%
Three major customers Accounts Recievable		4,900		4,900
Four major customers accounts recievable		6,000		6,000
Five major customers accounts recievable	6,500		6,500
Accumulated amortization	168,995		168,995		143,645
Uninsured balances	59,852		59,852		170,896
Amortization expense	143,645		143,645
Debt issuance costs	506,985		506,985		532,335
Non-cash impairment charge					$ 1,445,720
Impairment charge representation in goodwill					1.00%

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5. Fair Value Measurement (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurement

	Fair Value Measurement at September 30, 2013 Using
Financial assets:	Carrying Value as at September 30, 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	$	160,920	$	160,920	$	-	$	-

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17. Long-Term Debt (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery Loan	$ 9,122,302	$ 9,298,183
Construction and Funding Agreement	10,896,196	5,206,175
Notre Dame Debt	1,300,000	1,300,000
Capital Leases		2,119
Total	21,318,498	15,806,477
Less: Current portion of long-term debt	20,018,498	1,816,960
Long term debt	$ 1,300,000	$ 13,989,517

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11. Property, Plant and Equipment, Net (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Property Plant And Equipment Net Details
Refinery and facilities	$ 35,696,393	$ 34,000,199
Pipelines and facilities	1,233,811	1,233,811
Onshore separation and handling facilities	325,435	325,435
Land	577,965	577,965
Other property and equipment	559,486	577,567
Property, Plant and Equipment, Gross	38,393,090	36,714,977
Less: Accumulated depletion, depreciation and amortization	2,671,821	1,674,151
Property, Plant and Equipment less depreciation	35,721,269	35,040,826
Construction in Progress	187,004	821,259
Property, Plant and Equipment, Net	$ 35,908,273	$ 35,862,085

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13. Accounts Payable, Related Party

9 Months Ended

Sep. 30, 2013

Payables and Accruals [Abstract]

Accounts Payable, Related Party

LEH, which owns approximately 80% of our issued and outstanding common stock, manages and operates the Nixon Facility and our other operations (the “Services”) pursuant to a Management Agreement dated February 15, 2012 (the “Management Agreement”).

Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments 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 Management 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 Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement, which has an initial term of three years and successive one year renewals until August12, 2019 unless sooner terminated by GEL with 180 days prior written notice [see "Note (24) Subsequent Events" of this report for additional disclosures related to the Joint Marketing Agreement], (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by our Board of Directors (the “Board”) and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended September 30, 2013 and 2012 were $2,629,518 (approximately $2.68 per barrel) and $2,559,456 (approximately $2.70 per barrel). Aggregate amounts expensed for Services at the Nixon Facility for the nine months ended September 30, 2013 and 2012 were $8,099,371 (approximately $2.73 per barrel) and $5,862,121 (approximately $2.76 per barrel).  At September 30, 2013 and December 31, 2012, the amounts outstanding to LEH were $3,259,803 and $1,594,021, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets.

Herbert N. Whitney, a member of our Board, also currently serves as a consultant to LEH. Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, is a member of LEH. Tommy L. Byrd, our interim Chief Financial Officer, Treasurer and Assistant Secretary, is also an employee of LEH.

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9. Deposits

9 Months Ended

Sep. 30, 2013

Banking and Thrift [Abstract]

Deposits

Deposit balances consisted of the following:

	September 30,		December 31,
	2013		2012
Utility deposits	$	27,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,236,660	$	1,236,447

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18. Leases (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Leases Details Narrative
Rent expense	$ 25,161	$ 26,061	$ 76,382	$ 78,182

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16. Asset Retirement Obligations

9 Months Ended

Sep. 30, 2013

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 assets. Management believes that the Nixon Refinery and related facilities 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.

Oil and Gas Properties and Pipelines and Facilities Assets

We have AROs associated with the future abandonment, dismantlement and removal of our oil and gas properties, as well as our pipelines and facilities assets, as follows:

Asset retirment obligations at December 31, 2012	$	921,260
Liabilities settled		(8,243	)
Accretion expense		84,513
		997,530
Less:  current portion of asset retirement obligations		88,044
Asset retirement obligations, long-term balance
at September 30, 2013	$	909,486

For the three months ended September 30, 2013, we recognized $8 in abandonment expense for AROs 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. 

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14. Note Payable

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Note Payable

Our notes payable consists of a short-term note for financing costs and short-term capital leases, as follows:

	September 30,		December 31,
	2013		2012
Short-Term Note for Financing Costs	$	23,188	$	39,866
Short-Term Captial Leases		7,056		4,075
	$	30,244	$	43,941

Short-Term Note for Financing Costs.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing costs was $23,188 and $39,866 at September 30, 2013 and December 31, 2012, respectively.  The unsecured note, which bears interest at a base rate of 10% and a default rate of 18%, was originally due in January 2012.  The due date has been extended to December 2013. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $7,056 and $4,075 at September 30, 2013 and December 31, 2012, respectively.  Capital leases totaling $1,250, which were classified as long-term debt at December 31, 2012, have been re-classified to short-term debt at September 30, 2013 as they mature at various dates through February 2014.  These capital leases have interest rates ranging from 0% to 13.04%.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 14, 2013
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, 2013
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		10,580,973
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2013

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15. Accrued Expenses and Other Current Liabilities

9 Months Ended

Sep. 30, 2013

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	September 30,		December 31,
	2013		2012
Excise taxes	$	764,749	$	292,303
Transportation		-		69,551
Other payable		238,902		134,501
Property taxes		40,500		-
Unrealized hedging loss		-		136,100
Unearned revenue		-		92,783
	$	1,044,151	$	725,238

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13. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Payables and Accruals [Abstract]
Expense for service	$ 2,629,518	$ 2,559,456	$ 8,099,371	$ 5,862,121
Accounts payable, related party	$ 3,259,803		$ 3,259,803		$ 1,594,021

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12. Discontinued Operations (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Discontinued Operations Details
Revenue		$ 231,658		$ 674,797
Lease operating expenses		231,658		788,525
Depletion, depreciation and amortization		45,240		124,811
Abandonment expense
Impairment expense		3,858,427		3,858,427
Bad debt expense		321,732		321,732
Accretion expense		10,158		24,868
Total costs and expenses		4,568,366		5,118,363
Loss from discontinued operations, net of tax	$ 0	$ (4,336,708)	$ 0	$ (4,443,566)