10-Q/A

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly period ended   June 30, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934

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)

Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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(Section 232.405 of this chapter) during the preceding 12 months(or 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, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “small reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer      o                                                                                                            Accelerated filer                   o

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

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 (the “Common Stock”) outstanding as of August 13, 2012: 10,545,690.

Explanatory Note

The purpose of this Amendment No. 1 to the Blue Dolphin Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Securities and Exchange Commission on Auguest 14, 2012  (the “Form 10-Q”), is solely to furnish Exhibit 101 to the Form 10-Q in accordance with Rule 405 of Regulation S-T. Exhibit 101 to this report provides the consolidated financial statements and related notes from the Form 10-Q formatted in XBRL (eXtensible Business Reporting Language).

No other changes have been made to the Form 10-Q. This Amendment No. 1 to the Form 10-Q speaks as of the original filing date of the Form 10-Q, does not reflect events that may have occurred subsequent to the original filing date, and does not modify or update in any way disclosures made in the original Form 10-Q.

Pursuant to Rule 406T of Regulation S-T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

Item 6.	Exhibits
31.1*	Certification of CEO/CFO pursuant to Sec. 302
32.1*	Certification of CEO/CFO pursuant to Sec. 906

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.INS	XBRL Instance Document
101SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

_________

*           These exhibits were previously included or incorporated by reference in the Blue Dolphin Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Securities and Exchange Commission on August 14, 2012.

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
September 11, 2012	/s/ JONATHAN P. CARROLL
	Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)
September 11, 2012	/s/ TOMMY L. BYRD
	Tommy L. Byrd Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

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5. Fair Value Measurement (Details) (USD $)	Jun. 30, 2012
Financial liabilties:
Commodity contracts	$ 126,983
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	126,983
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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16. Stock Options (Details 1) (USD $)	Jun. 30, 2012
Number Outstanding	26,402
Weighted Average Remaining Contractual Life (Years)	1 year 4 months 24 days
Weighted Average Exercise Price, Outstanding	$ 13.3
Number Exercisable	26,402
Weighted Average Exercise Price, Exercisable	$ 13.3
ExercisePriceRange1Member
Range of Exercise Price, Minimum	$ 2.45
Range of Exercise Price, Maximum	$ 5.60
Number Outstanding	10,118
Weighted Average Remaining Contractual Life (Years)	9 months 18 days
Weighted Average Exercise Price, Outstanding	$ 3.06
Number Exercisable	10,118
Weighted Average Exercise Price, Exercisable	$ 3.06
ExercisePriceRange2Member
Range of Exercise Price, Minimum	$ 13.30
Range of Exercise Price, Maximum	$ 19.67
Number Outstanding	16,284
Weighted Average Remaining Contractual Life (Years)	1 year 9 months 18 days
Weighted Average Exercise Price, Outstanding	$ 19.67
Number Exercisable	16,284
Weighted Average Exercise Price, Exercisable	$ 19.67

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12. Long-Term Debt (Details1) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Cost	$ 9,396	$ 9,396
Less: Accumulated amortization	4,071	3,602
Equipment held under capital leases	$ 5,325	$ 5,794

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17. Subsequent Events (Details Narrative) (USD $)	Jun. 30, 2012
ConstructionAndFundingAgreementMember
Advances under agreement	$ 7,600,000
JointMarketingAgreementMember
Deficit under agreement	4,300,000
Deficit paid	$ 1,800,000

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11. Asset Retirement Obligations (Details) (USD $)	3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Asset Retirement Obligations Details
Fair value of asset retirement obligations at February 15, 2012			$ 1,294,139
Liabilities incurred
Liabilities settled			(3,685)
Accretion expense	41,685		65,460	65,460
Asset retirement obligations as of June 30, 2012	1,355,914		1,355,914	1,355,914
Less current portion of asset retirement obligations	149,271		149,271	149,271
Asset retirement obligations, long-term balance at June 30, 2012	$ 1,206,643		$ 1,206,643	$ 1,206,643

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15. Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2012

Income (loss) per common share:

Earnings per share

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2012	2011	2012	2011
Net income (loss)	$  (7,333,399)	$       160,525	$  (9,303,293)	$       378,917
Basic and Diluted
Weighted average number of shares of common
stock outstanding and potential dilutive shares
of common stock	6,972,414	1	6,320,378	1
Per share amount	$         (1.05)	$       160,525	$         (1.47)	$       378,917

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2. Acquisition (Tables)

6 Months Ended

Jun. 30, 2012

Business Combinations [Abstract]

Provisional price allocation for net assets acquired

	As Reported		Revised Purchase
	February 15, 2012	Adjustments	Price Allocation
Current assets	$      2,466,901	$             -	$                -
Oil and gas properties	1,503,596	-	-
Pipelines	4,466,273	-	-
Onshore separation and handling facilities	325,435	-	-
Land	473,225	-	-
Other property and equipment	282,972	-	-
Other long term assets	9,463	-	-
Trade name	184,368	-	-
Goodwill	8,667,401	-	-
Total assets acquired	18,379,634	-	-
Current liabilities	333,480	-	-
Deferred Taxes	-	-	-
Long term liabilities	-	-	-
Total liabilities assumed	333,480	-	-
Net assets acquired	$    18,046,154	$             -	$                -

Supplemental Pro Forma Information

	Blue Dolphin	LE	Consolidated	Blue Dolphin	LE	Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$                -	$                -	$                -	$                -	$                -	$                -
Pipeline operations	-	-	-	-	-	-
Oil and gas sales	-	-	-	-	-	-
Total revenue from operations	-	-	-	-	-	-
COST OF OPERATIONS
Cost of refined products sold	-	-	-	-	-	-
Refinery operating expenses	-	-	-	-	-	-
Pipeline operating expenses	-	-	-	-	-	-
Lease operating expenses	-	-	-	-	-	-
Depletion, depreciation and amortization	-	-	-	-	-	-
General and administrative expenses	-	-	-	-	-	-
Accretion expense	-	-	-	-	-	-
Total cost of operations	-	-	-	-	-	-
Loss from operations	-	-	-	-	-	-
OTHER INCOME (EXPENSE)
Net tank rental revenue	-	-	-	-	-	-
Interest and other income	-	-	-	-	-	-
Interest expense	-	-	-	-	-	-
Rental income, related party	-	-	-	-	-	-
Dividend income	-	-	-	-	-	-
Forgiveness of debt income	-	-	-	-	-	-
Total other income (expense)			-			-
Loss before income taxes	-	-	-	-	-	-
Income tax expense	-	-	-	-	-	-
Net loss	$                -	$                -	$                -	$                -	$                -	$                -

No columns for adjustments are reflected as there were no adjustments for the periods indicated.

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	Historical		Pro Forma	Historical		Pro Forma
	Blue Dolphin	LE	Consolidated	Blue Dolphin	LE	Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$                -	$                -	$                -	$                -	$                -	$                -
Pipeline operations	-	-	-	-	-	-
Oil and gas sales	-	-	-	-	-	-
Total revenue from operations	-	-	-	-	-	-
COST OF OPERATIONS
Cost of refined products sold	-	-	-	-	-	-
Refinery operating expenses	-	-	-	-	-	-
Pipeline operating expenses	-	-	-	-	-	-
Lease operating expenses	-	-	-	-	-	-
Depletion, depreciation and amortization	-	-	-	-	-	-
General and administrative expenses	-	-	-	-	-	-
Accretion expense	-	-	-	-	-	-
Total cost of operations	-	-	-	-	-	-
Loss from operations	-	-	-	-	-	-
OTHER INCOME (EXPENSE)
Net tank rental revenue	-	-	-	-	-	-
Interest and other income	-	-	-	-	-	-
Interest expense	-	-	-	-	-	-
Rental income, related party	-	-	-	-	-	-
Dividend income	-	-	-	-	-	-
Forgiveness of debt income	-	-	-	-	-	-
Total other income (expense)			-			-
Loss before income taxes	-	-	-	-	-	-
Income tax expense	-	-	-	-	-	-
Net loss	$                -	$                -	$                -	$                -	$                -	$                -

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13. Income Taxes (Details Narrative) (USD $)	Jun. 30, 2012
Income Taxes Details Narrative
Accrued Texas margins tax	$ 13,144

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7. Inventories (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 445,857	$ 2,193,864
Naphtha	2,759,078	1,067,011
Atmospheric gas oil	400,445	1,010,877
Other liquids	55,068	64,486
Propane	43,877	59,599
Crude	74,209	134,289
Supplies		3,835
Inventory	$ 3,778,534	$ 4,533,961

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3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Accounting Policies [Abstract]
Restricted cash	$ 192,542		$ 192,542		$ 192,004
Perecentage of revenue from major customers	79.00%		69.00%
Three major customers Accounts Recievable	3,400,000		3,400,000
Accumulated amortization	126,746		126,746		109,847
Amortization expense	8,450	8,450	16,899	16,899
Debt issuance costs			$ 675,980

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16. Stock Options (Details Narrative) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Issuance of restricted common stock expense	$ 20,000	$ 40,000
Common stock reserved for issuance upon exercise of outstanding options	26,402	26,402

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12. Long-Term Debt (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Refinery Loan	$ 9,315,826	$ 9,669,173
Notre Dame Debt	1,300,000	1,300,000
Construction and Funding Agreement	7,572,040	3,319,193
Captial Leases	2,933	6,237
Total	18,190,799	14,294,603
Less: Current portion of long-term debt	1,846,812	1,839,501
Long term debt	$ 16,343,987	$ 12,455,102

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3. Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Accounting Policies [Abstract]

Significant Accounting Policies

Basis of Presentation

We have prepared our unaudited condensed consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”).  In the opinion of management, such condensed consolidated financial statements reflect all adjustments necessary to present fair condensed 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.

The results of operations for the three and six months ended June 30, 2012, are not necessarily indicative of the results of operations to be expected for the full year ending December 31, 2012.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of condensed consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these unaudited condensed 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.

Restricted Cash

Restricted cash was $192,542 and $192,004 at June 30, 2012 and December 31, 2011, 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.  As of June 30, 2012 and December 31, 2011, there was no allowance recorded related to trade accounts receivable.

We had three customers that accounted for 79% of our total revenue for the three months ended June 30, 2012.  We had three customers that accounted for approximately 69% of our total revenue for the six months ended June 30, 2012. The three customers represented approximately $3.4 million of accounts receivable at June 30, 2012.

Inventory

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

Price-Risk Management Activities

In May 2012, we implemented 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 our refined product inventory commodity price risk.  We follow ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not sugject to hedge accounting treatment under ASC 815.  Accordingly, even though such hedge positions are direct contractual obligations of Genesis and not us, we nevertheless 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. As a startup facility, maintenance turnaround expenses are not material and are not expected to be material in the next twelve to eighteen months. 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 over the estimated useful lives of 25 years when the refinery and facilities are placed in service.

Management has evaluated the guidance in the ASC related to asset retirement obligation for its 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 ASC guidance for estimating asset retirement obligations 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 six months ended June 30, 2012 or 2011.

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.  We use one cost center for domestic properties and one cost center for foreign properties. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.

Current estimated proved oil and gas reserves were based on reports prepared by third-party petroleum engineering consulting firms.  For determining impairment of our oil and gas properties, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to a “ceiling,” which is determined based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances.  Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense.  We did not have any impairment of our oil and gas properties for the three and six months ended June 30, 2012.

Pipelines and Facilities Assets.  Pipelines and facilities assets are recorded at cost.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with the 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.  We did not have any impairment of our pipelines and facilities for the three and six months ended June 30, 2012.

Construction in Progress.  Construction in progress consists of costs we incurred to purchase and refurbish the Nixon Facility.  Amounts were capitalized as incurred and depreciation began when the Nixon Facility became operational. Capitalized interest, which was added to the cost of the underlying assets, will be amortized over the useful life of the Nixon Facility.

Trade Name

In connection with the Acquisition, we recognized $303,346 as trade name.  We have determined our trade name to have an indefinite useful life.  We perform an evaluation for impairment of our trade name either annually or when events and circumstances indicate an impairment test is considered necessary.

Goodwill

We recognized goodwill in connection with our Acquisition.  Goodwill has an indefinite useful life and reflects the amount of the purchase consideration that exceeded the fair value of Blue Dolphin’s net assets.  We perform an evaluation for impairment of goodwill either annually or when events and circumstances indicate a goodwill impairment test is considered necessary.

Debt Issue Costs

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 of $675,980, net of accumulated amortization in the amount of $126,746 and $109,847 at June 30, 2012 and at December 31, 2011, respectively, are being amortized over the life of the loan.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended June 30, 2012 and 2011.  Amortization expense was $16,899 for the six months ended June 30, 2012 and 2011.

Revenue Recognition

Refined Products Revenue.  We sell various refined products including naphtha, distillates and atmospheric gas oil.  Revenue from refined product sales is recognized when title passes, while revenue from services is recognized when services are provided. Title passage occurs when refined products are delivered in accordance with the terms of the respective sales agreements. In addition, revenue is not recognized until sales prices are fixed or determinable and collectability is reasonably assured.

Revenue for refined products sold is recorded upon delivery of the refined products to customers, which is the point at which title is transferred.  The customer assumes the risk of loss when payment is received or collection is reasonably assured. Transportation, shipping and handling costs incurred are included in cost of refined products sold. Excise and other taxes 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 June 30, 2012 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 provide for income taxes using the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The evaluation of a tax position is a two-step process. The first step is a recognition process whereby we determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, we presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Recently Issued Accounting Pronouncements

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

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8. Property, Plant and Equipment, Net (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Property Plant And Equipment Net Details
Refinery and facilities	$ 33,784,022
Oil and gas properties (full-cost method)	5,144,973
Pipelines and facilities	9,223,836
Onshore separation and handling facilities	325,435
Land	577,965	104,740
Other property and equipment	521,630	217,136
Property, Plant and Equipment, Gross	49,577,861	321,876
Less: Accumulated depletion, depreciation and amortization	855,084	62,443
Property, Plant and Equipment less depreciation	48,722,777	259,433
Construction in Progress	314,995	32,048,496
Property, Plant and Equipment, Net	$ 49,037,772	$ 32,307,929

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7. Inventories (Tables)

6 Months Ended

Jun. 30, 2012

Inventory Disclosure [Abstract]

Inventories

	June 30,	December 31,
	2012	2011
Low-sulfur diesel	$      445,857	$      2,193,864
Naphtha	2,759,078	1,067,011
Atmospheric gas oil	400,445	1,010,877
Other liquids	55,068	64,486
Propane	43,877	59,599
Crude	74,209	134,289
Supplies	-	3,835
	$   3,778,534	$      4,533,961

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6. Refined Products Inventory Risk Management (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

	Notional Contract Volumes by Year of Maturity
	2012		2013		2014		2015
Inventory positions (futures):
Refined products - net short (long) positions		22		-		-		-

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9. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012	Dec. 31, 2011
Payables and Accruals [Abstract]
Services provided by LEH	$ 1,028,817	$ 1,028,817	$ 908,139
Expense for service	$ 2,239,914	$ 3,302,665

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

6 Months Ended

Jun. 30, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

	June 30,	December 31,
	2012	2011
Low-sulfur diesel	$      445,857	$      2,193,864
Naphtha	2,759,078	1,067,011
Atmospheric gas oil	400,445	1,010,877
Other liquids	55,068	64,486
Propane	43,877	59,599
Crude	74,209	134,289
Supplies	-	3,835
	$   3,778,534	$      4,533,961

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11. Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Fair value of asset retirement obligations at February 15, 2012	$         1,294,139
Liabilities incurred	-
Liabilities settled	(3,685)
Accretion expense	65,460
Asset retirement obligations as of June 30, 2012	1,355,914
Less:  current portion of asset retirement obligations	149,271
Asset retirement obligations, long-term balance
at June 30, 2012	$         1,206,643

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2. Acquisition

6 Months Ended

Jun. 30, 2012

Business Combinations [Abstract]

Acquisition

During the first quarter of 2012, Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE, a Delaware limited liability company, from Lazarus Energy Holdings, LLC, a Delaware limited liability company (“LEH”) (the “Acquisition”).  The Acquisition was effective February 15, 2012.   As consideration for LE, Blue Dolphin issued, in reliance on the exemption provided by Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), 8,393,560 shares of common stock, par value $0.01 per share (the “Common Stock”), subject to anti-dilution adjustments, to LEH (the “Original BDEC Shares”).  Additionally, on February 21, 2012, pursuant to anti-dilution provisions, Blue Dolphin issued, in reliance on the exemption provided by Section 4(2) of the Securities Act, 32,896 shares of Common Stock to LEH (the “Anti-Dilution Shares” and together with the Original BDEC Shares, the “BDEC Shares”). As a result of Blue Dolphin’s issuance of the BDEC Shares, LEH owns 80% of Blue Dolphin’s issued and outstanding Common Stock.  The issuance of the BDEC Shares to LEH resulted in a change in control of Blue Dolphin.  

LE owns a petroleum refinery located in Nixon, Texas (the “Nixon Facility”). The processing plant at the Nixon Facility is currently in a recommissioning phase and has not yet reached its full operational capacity.  The tank farm has 120,000 barrels of crude oil storage capacity and 148,000 barrels of refined product storage capacity.  The Nixon Facility has the capability to produce products such as Non-Road, Locomotive, and Marine Diesel Fuels, kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil.  LE has leased 20,000 barrels of refined product storage capacity to Genesis Energy, LLC (“Genesis”). Once the lease expires, we plan to use the tanks for our own operations.

The Acquisition has been accounted for as a reverse merger using accounting principles applicable to reverse acquisitions whereby the financial statements subsequent to the date of the transaction are presented as a continuation of LE.  Under reverse acquisition accounting, LE (the legal subsidiary) has been treated as the accounting parent (acquirer) and Blue Dolphin (the legal parent) has been treated as the accounting subsidiary (acquiree).  Accordingly, the financial statements subsequent to the date of the transaction are presented herein as the continuation of LE.

The value assigned to the purchase price was allocated to Blue Dolphin’s tangible and intangible assets and liabilities based on their fair values on the transaction closing date.  LE’s purchase price to acquire Blue Dolphin was based on the fair value of Blue Dolphin’s issued and outstanding common stock at February 15, 2012, which was 2,098,390 shares, multiplied by Blue Dolphin’s closing stock price of $8.60 on February 15, 2012, the transaction closing date.  This resulted in a fair value assessment of Blue Dolphin of $18,046,154.

In connection with the Acquisition, we engaged an independent third-party to fair value the net assets of Blue Dolphin.  Fair value of financial and non-financial assets and liabilities is defined as an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

The following table summarizes the purchase price allocation of the net assets acquired as of the acquisition date, as well as the measurement period adjustments that were made in the second quarter of 2012:

The above estimated fair values of the assets acquired and liabilities assumed are based on information that was available as of the acquisition date to estimate the fair value of assets acquired and liabilities assumed.  As of June 30, 2012 the measurement period adjustments for Blue Dolphin are complete.

Goodwill recognized in the transaction is related to the expected value to be received from the combination of LE’s crude oil and condensate processing facility and Blue Dolphin’s pipeline and facilities, oil and gas properties and operational expertise.

From the date of the Acquisition (February 15, 2012) until June 30, 2012, Blue Dolphin’s revenue and net loss included in the condensed consolidated statements of operations for the three months ended June 30, 2012, was $374,557, and  $976,811 respectively.  Blue Dolphin’s revenue and net loss included in the condensed consolidated statements of operations for the six months ended June 30, 2012, was $644,807, and $1,490,351 respectively.

	February 15, 2012		Measurement			Purchase Price Allocation
	As Intially		Period			(As Adjusted)
	Reported		Adjustments			February 15, 2012
Current assets	$	2,466,901	$	-		$	2,466,901
Oil and gas properties		1,503,596		3,639,279			5,142,875
Pipelines		4,466,273		4,757,563			9,223,836
Onshore separation and handling facilities		325,435		-			325,435
Land		473,225		-			473,225
Other property and equipment		282,972		-			282,972
Other long term assets		9,463		-			9,463
Trade name		184,368		118,978			303,346
Goodwill		8,667,401		(7,221,681	)		1,445,720
Total assets acquired		18,379,634		1,294,139			19,673,773
Current liabilities		333,480		-			333,480
Asset retirement obligations		-		1,294,139			1,294,139
Total liabilities assumed		333,480		1,294,139			1,627,619
Net assets acquired	$	18,046,154	$	-		$	18,046,154

Supplemental Pro Forma Information

The following pro forma condensed consolidated statements of operations for the three and six months ended June 30, 2012 and June 30, 2011 consolidate the historical consolidated statements of operations of Blue Dolphin and LE giving effect to the Acquisition as if it had occurred on January 1, 2011, respectively.  The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only:

	Three Months Ended June 30, 2012									Six Months Ended June 30, 2012
	Historical						Proforma			Historical						Proforma
	Blue Dolphin			LE			Consolidated			Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$	-		$	84,416,296		$	84,416,296		$	-		$	130,187,259		$	130,187,259
Pipeline operations		124,476			-			124,476			233,810			-			233,810
Oil and gas sales		250,081			-			250,081			560,779			-			560,779
Total revenue from operations		374,557			84,416,296			84,790,853			794,589			130,187,259			130,981,848
COST OF OPERATIONS
Cost of refined products sold		-			88,051,229			88,051,229			-			133,692,455			133,692,455
Refinery operating expenses		-			2,239,914			2,239,914			-			3,302,665			3,302,665
Pipeline operating expenses		127,502			-			127,502			296,585			-			296,585
Lease operating expenses		298,962			-			298,962			603,399			-			603,399
Depletion, depreciation and amortization		228,184			292,206			520,390			352,771			487,110			839,881
General and administrative expenses		656,056			78,664			734,720			1,196,126			237,125			1,433,251
Accretion expense		41,685			-			41,685			77,347			-			77,347
Total cost of operations		1,352,389			90,662,013			92,014,402			2,526,228			137,719,355			140,245,583
Loss from operations		(977,832	)		(6,245,717	)		(7,223,549	)		(1,731,639	)		(7,532,096	)		(9,263,735	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			81,364			81,364			-			175,319			175,319
Interest and other income		1,877			388			2,265			4,216			538			4,754
Interest expense		(856	)		(274,477	)		(275,333	)		(856	)		(507,994	)		(508,850	)
Total other income (expense)		1,021			(192,725	)		(191,704	)		3,360			(332,137	)		(328,777	)
Loss before income taxes		(976,811	)		(6,438,442	)		(7,415,253	)		(1,728,279	)		(7,864,233	)		(9,592,512	)
Income tax expense		-			17,419			17,419			-			(13,144	)		(13,144	)
Net loss	$	(976,811	)	$	(6,421,023	)	$	(7,397,834	)	$	(1,728,279	)	$	(7,877,377	)	$	(9,605,656	)

No columns for adjustments are reflected as there were no adjustments for the periods indicated.

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Historical						Proforma			Historical						Proforma
	Blue Dolphin			LE			Consolidated			Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Pipeline operations	$	267,375		$	-		$	267,375		$	610,005		$	-		$	610,005
Oil and gas sales		353,027			-			353,027			702,731			-			702,731
Total revenue from operations		620,402			-			620,402			1,312,736			-			1,312,736
COST OF OPERATIONS
Pipeline operating expenses		245,032			-			245,032			466,366			-			466,366
Lease operating expenses		271,836			-			271,836			530,279			-			530,279
Depletion, depreciation and amortization		136,828			4,306			141,134			283,536			8,614			292,150
General and administrative expenses		349,245			177,112			526,357			822,636			290,940			1,113,576
Accretion expense		32,993			-			32,993			66,079			-			66,079
Total cost of operations		1,035,934			181,418			1,217,352			2,168,896			299,554			2,468,450
Loss from operations		(415,532	)		(181,418	)		(596,950	)		(856,160	)		(299,554	)		(1,155,714	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			353,709			353,709			-			696,454			696,454
Interest and other income		1,598			295			1,893			10,138			6,389			16,527
Interest expense		-			(12,061	)		(12,061	)		-			(24,372	)		(24,372	)
Total other income (expense)		1,598			341,943			343,541			10,138			678,471			688,609
Income (loss) before income taxes		(413,934	)		160,525			(253,409	)		(846,022	)		378,917			(467,105	)
Income tax expense		-			-			-			-			-			-
Net income (loss)	$	(413,934	)	$	160,525		$	(253,409	)	$	(846,022	)	$	378,917		$	(467,105	)

No columns for adjustments are reflected as there were no adjustments for the periods indicated.

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12. Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Long term debt

	June 30,	December 31,
	2012	2011
Refinery Loan	$   9,315,826	$      9,669,173
Notre Dame Debt	1,300,000	1,300,000
Construction and Funding Agreement	7,572,040	3,319,193
Captial Leases	2,933	6,237
	18,190,799	14,294,603
Less: Current portion of long-term debt	1,846,812	1,839,501
	$ 16,343,987	$    12,455,102

Equipment held under capital leases

	June 30,	December 31,
	2012	2011
Cost	$         9,396	$            9,396
Less:  Accumulated amortization	4,071	3,602
	$         5,325	$            5,794

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6. Refined Products Inventory Risk Management (Details) (Refined products - net short (long) positions)	Jun. 30, 2012
Refined products - net short (long) positions
2012	22
2013
2014
2015

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16. Stock Options (Details) (USD $)	6 Months Ended
	Jun. 30, 2012
Shares
Options outstanding at December 31, 2011	28,887
Options granted
Options exercised
Options expired or cancelled	(2,485)
Options outstanding at June 30, 2012	26,402
Options exercisable at June 30, 2012	26,402
Weighted Average Exercise Price
Options outstanding at December 31, 2011	$ 13.29
Options granted
Options exercised
Options expired or cancelled
Options outstanding at June 30, 2012	$ 13.3
Options exercisable at June 30, 2012	$ 13.3
Weighted Average Remaining Contractual Life
Options outstanding at June 30, 2012	1 year 4 months 24 days
Options exercisable at June 30, 2012	1 year 4 months 24 days
Aggregate Intrinisic Value
Options outstanding at June 30, 2012
Options exercisable at June 30, 2012

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Cash and cash equivalents	$ 478,288	$ 1,822
Restricted cash	192,542	192,004
Accounts receivable	6,113,419
Prepaid expenses and other current assets	247,933	58,713
Deposits	1,248,947	473,026
Inventory	3,778,534	4,533,961
Total current assets	12,059,663	5,259,526
Total property and equipment, net	49,037,772	32,307,929
Debt issue costs	549,234	566,133
Other assets	14,221	10,468
Trade name	303,346
Goodwill	1,445,720
TOTAL ASSETS	63,409,956	38,144,056
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	14,261,292	4,841,859
Accounts payable, related party	1,028,817	908,139
Note payable	43,392	46,318
Asset retirement obligations, current portion	149,271
Accrued expenses and other current liabilities	931,361	744,921
Interest payable, current portion	1,371,208	995,916
Long-term debt, current portion	1,846,812	1,839,501
Total current liabilities	19,632,153	9,376,654
Asset retirement obligations, net of current portion	1,206,643
Long term debt, net of current portion	16,343,987	12,455,102
Long term interest payable, net of current portion	753,929	650,214
Total long-term liabilities	18,304,559	13,105,316
TOTAL LIABILITIES	37,951,276	22,481,970
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,545,690 and 2,098,390 shares issued and outstanding at June 30, 2012 and December 31, 2011, respectively)	105,457	20,984
Additional paid-in capital	36,459,818	17,365,405
Accumulated deficit	(11,092,031)	(1,724,303)
Total stockholders' equity	25,473,244	15,662,086
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 63,409,956	$ 38,144,056

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10. Note Payable (Details Narrative) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Short-term note	$ 31,317	$ 46,318
Unsecured note balance	$ 12,075

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Condensed Consolidated Statements of Cash Flows (Parenthetical) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Statement of Cash Flows [Abstract]
Cash acquired from business acquisition	$ 1,674,594

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2. Acquisition (Details) (USD $)	Jun. 30, 2012	Feb. 14, 2012 As Reported	Feb. 14, 2012 Adjustments	Feb. 14, 2012 Revised Purchase Price Allocation
Current assets		$ 2,466,901		$ 2,466,901
Oil and gas properties		1,503,596	3,639,279	5,142,875
Pipelines		4,466,273	4,757,563	9,223,836
Onshore separation and handling facilities		325,435		325,435
Land		473,225		473,225
Other property and equipment		282,972		282,972
Other long term assets		9,463		9,463
Trade name		184,368	118,978	303,346
Goodwill		8,667,401	(7,221,681)	1,445,720
Total assets acquired		18,379,634	1,294,139	19,673,773
Current liabilities		333,480		333,480
Asset retirement obligations	1,355,914		1,294,139	1,294,139
Total liabilities assumed		333,480	1,294,139	1,627,619
Net assets acquired		$ 18,046,154		$ 18,046,154

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16. Stock Options

6 Months Ended

Jun. 30, 2012

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

Stock Options

Following the Acquisition, the Compensation Committee of the Board approved the continuation of Blue Dolphin’s 2000 Stock Incentive Plan (the “Plan”).  LE did not have any stock option plan.  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 Plan provides that upon a change in control, the Compensation Committee may: i) accelerate the vesting of options, cancel options and make payments in respect thereof in cash in accordance with the terms of the Plan, (ii) adjust the outstanding options as appropriate to reflect such change in control or (iii) provide that each option shall thereafter be exercisable for the number and class of securities or property that the optionee would have been entitled to receive had the option been exercised.  The Plan provides that a change of control occurs if any person, entity or group acquires or gains ownership or control of more 50% of the outstanding Common Stock or, if after certain enumerated transactions, the persons who were directors before such transactions cease to constitute a majority of the Board.  Issuance of Common Stock to LEH in connection with the Acquisition resulted in a change in control under the Plan. The Compensation Committee of the Board approved the continuation of the Plan and determined that each option outstanding under the Plan would remain exercisable for the number and class of securities or property that the optionee was entitled to receive prior to the Acquisition.  As of the date of the Acquisition, all options granted under the Plan had vested.

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 the 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 six months ended June 30, 2012.

At June 30, 2012, there were a total of 26,402 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		Aggregate Intrinisic Value
Options outstanding at December 31, 2011		28,887		$	13.29
Options granted		-		$	-
Options exercised		-		$	-
Options expired or cancelled		(2,485	)	$	-
Options outstanding at June 30, 2012		26,402		$	13.30		1.4	$	-
Options exercisable at June 30, 2012		26,402		$	13.30		1.4	$	-

The following table summarizes additional information about stock options outstanding at June 30, 2012:

		Options Outstanding						Options Exercisable
Range of Exercise Prices		Number Outstanding		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price		Number Exercisable		Weighted Average Exercise Price
$	2.45 to $5.60		10,118		0.8	$	3.06		10,118	$	3.06
$	13.30 to $19.67		16,284		1.8	$	19.67		16,284	$	19.67
			26,402		1.4	$	13.30		26,402	$	13.30

We recognized no compensation expense for vested stock options for the three and six months ended June 30, 2012 and June 30, 2011.  As of June 30, 2012, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

We recognized $20,000 and $40,000 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for the three and six months ended June 30, 2012, respectively.

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2. Acquisition (Details1) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Historical Blue Dolphin
REVENUE FROM OPERATIONS
Refined product sales
Pipeline operations	124,476	267,375	233,810	610,005
Oil and gas sales	250,081	353,027	560,779	702,731
Total revenue from operations	374,557	620,402	794,589	1,312,736
COST OF OPERATIONS
Cost of refined products sold
Refinery operating expenses
Pipeline operating expenses	127,502	245,032	296,585	466,366
Lease operating expenses	298,962	271,836	603,399	530,279
Depletion, depreciation and amortization	228,184	136,828	352,771	283,536
General and administrative expenses	656,056	349,245	1,196,126	822,636
Accretion expense	41,685	32,993	77,347	66,079
Total cost of operations	1,352,389	1,035,934	2,526,228	2,168,896
Loss from operations	(977,832)	(415,532)	(1,731,639)	(856,160)
OTHER INCOME (EXPENSE)
Net tank rental revenue
Interest and other income	1,877	1,598	4,216	10,138
Interest expense	(856)		(856)
Total other income (expense)	1,021	1,598	3,360	10,138
Loss before income taxes	(976,811)	(413,934)	(1,728,279)	(846,022)
Income tax expense
Net loss	(976,811)	(413,934)	(1,728,279)	(846,022)
Historical LE
REVENUE FROM OPERATIONS
Refined product sales	84,416,296		130,187,259
Pipeline operations
Oil and gas sales
Total revenue from operations	84,416,296		130,187,259
COST OF OPERATIONS
Cost of refined products sold	88,051,229		133,692,455
Refinery operating expenses	2,239,914		3,302,665
Pipeline operating expenses
Lease operating expenses
Depletion, depreciation and amortization	292,206	4,306	487,110	8,614
General and administrative expenses	78,664	177,112	237,125	290,940
Accretion expense
Total cost of operations	90,662,013	181,418	137,719,355	299,554
Loss from operations	(6,245,717)	(181,418)	(7,532,096)	(299,554)
OTHER INCOME (EXPENSE)
Net tank rental revenue	81,364	353,709	175,319	696,454
Interest and other income	388	295	538	6,389
Interest expense	(274,477)	(12,061)	(507,994)	(24,372)
Total other income (expense)	(192,725)	341,943	(332,137)	678,471
Loss before income taxes	(6,438,442)	160,525	(7,864,233)	378,917
Income tax expense	17,419		(13,144)
Net loss	(6,421,023)	160,525	(7,877,377)	378,917
Pro Forma Consolidated
REVENUE FROM OPERATIONS
Refined product sales	84,416,296		130,187,259
Pipeline operations	124,476	267,375	233,810	610,005
Oil and gas sales	250,081	353,027	560,779	702,731
Total revenue from operations	84,790,853	620,402	130,981,848	1,312,736
COST OF OPERATIONS
Cost of refined products sold	88,051,229		133,692,455
Refinery operating expenses	2,239,914		3,302,665
Pipeline operating expenses	127,502	245,032	296,585	466,366
Lease operating expenses	298,962	271,836	603,399	530,279
Depletion, depreciation and amortization	520,390	141,134	839,881	292,150
General and administrative expenses	734,720	526,357	1,433,251	1,113,576
Accretion expense	41,685	32,993	77,347	66,079
Total cost of operations	92,014,402	1,217,352	140,245,583	2,468,450
Loss from operations	(7,223,549)	(596,950)	(9,263,735)	(1,155,714)
OTHER INCOME (EXPENSE)
Net tank rental revenue	81,364	353,709	175,319	696,454
Interest and other income	2,265	1,893	4,754	16,527
Interest expense	(275,333)	(12,061)	(508,850)	(24,372)
Total other income (expense)	(191,704)	343,541	(328,777)	688,609
Loss before income taxes	(7,415,253)	(253,409)	(9,592,512)	(467,105)
Income tax expense	17,419		(13,144)
Net loss	$ (7,397,834)	$ (253,409)	$ (9,605,656)	$ (467,105)

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3. Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Accounting Policies [Abstract]

Basis of presentation

Basis of Presentation

We have prepared our unaudited condensed consolidated financial statements, in accordance with U.S. generally accepted accounting principles (“GAAP”) as codified by the Financial Accounting Standards Board in its Accounting Standards Codification (“ASC”), pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). In the opinion of management, such condensed consolidated financial statements reflect all adjustments necessary to present fair condensed 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 audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

The results of operations for the three and six months ended June 30, 2012, are not necessarily indicative of the results of operations to be expected for the year ending December 31, 2012.

Use of Estimates

 We have made a number of estimates and assumptions related to the reporting of condensed consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these unaudited condensed 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.

Restricted Cash

Restricted cash was $192,542 and $192,004 at June 30, 2012 and December 31, 2011, 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. As of June 30, 2012 and December 31, 2011, there was no allowance recorded related to trade accounts receivable.We had three customers that accounted for 79% of our total revenue for the three months ended June 30, 2012. We had three customers that accounted for approximately 69% of our total revenue for the six months ended June 30, 2012. The three customers represented approximately $3.4 million of accounts receivable at June 30, 2012.

Inventory

Inventory

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

Price-Risk Management Activities

In May 2012, LE implemented an inventory management policy under which GEL Tex Marketing, LLC, a Genesis Energy, LLC (“Genesis”) affiliate (“GEL”)may use derivative instruments to reduce our refined product commodity price risk. We followASC guidance forderivatives and hedging related to a fair value hedge, which requires that we record the fair value of the hedge on our balance sheet each quarter.  Changes in the fair value from quarter to quarter are recognized in our income statement.

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. As a startup facility, maintenance turnaround expenses are not material and are not expected to be material in the next twelve to eighteen months. 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 facilitiesis computed using the straight-line method over the estimated useful lives of 25 years when the refinery and facilities are placed in service.

Managementhas evaluated the guidance in the ASC related to asset retirement obligation for its refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery andfacilities. Further, management believes that these assets have indeterminate lives under ASC guidance for estimating asset retirement obligations 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 six months ended June 30, 2012 or 2011.

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. We use one cost center for domestic properties and one cost center for foreign properties. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.

Current estimated proved oil and gas reserves were based on reports prepared by third-party petroleum engineering consulting firms. For determining impairment of our oil and gas properties, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to a “ceiling,” which is determined based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We did not have any impairment of our oil and gas properties for the three and six months ended June 30, 2012.

Pipelines and Facilities Assets.Pipelines and facilities assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with the 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. We did not have any impairment of our pipelines and facilities for the three and six months ended June 30, 2012.

Construction in Progress.Construction in progress consists of costs we incurred to purchase and refurbish the Nixon Facility. Amounts were capitalized as incurred and depreciation began when the Nixon Facilitybecame operational. Capitalized interest, which was added to the cost of the underlying assets, will be amortized over the useful life of the Nixon Facility.

Trade Name

Trade Name

In connection with the Acquisition, we recognized $184,368 as trade name. We have determined our trade name to have an indefinite useful life. We perform an evaluation for impairment of our trade name either annually or when events and circumstances indicate an impairment test is considered necessary.

Goodwill

Goodwill

We recognized goodwill in connection with our Acquisition. Goodwill has an indefinite useful life and reflects the amount of the purchase consideration that exceeded the fair value of Blue Dolphin’s net assets. We perform an evaluation for impairment of goodwill either annually or when events and circumstances indicate a goodwill impairment test is considered necessary.

Debt Issue Costs

Debt Issue Costs

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 of $675,980, net of accumulated amortization in the amount of $_______ and $109,847 at June 30, 2012 and at December 31, 2011, respectively, are being amortized over the life of the loan. Amortization expense was $_____ for the three months ended June 30, 2012 and 2011, and is included in interest expense.

Revenue Recognition

Revenue Recognition

Refined Products Revenue. We sell various refined products including naphtha, distillates and residual fuel.  Revenues related to the sale of products are recognized when title passes, while service revenues are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.

Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred. The customer has assumed the risk of loss when payment has been received or collection is reasonably assured. Transportation, shipping and handling costs incurred are included in cost of products sold. Excise and other taxes collected from customers and remitted to governmental authorities are not included in revenue.

Tank Storage Rental Revenue. Revenue from tank storage 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 June 30, 2012 was not material.

Pipeline Transportation Revenue. Revenue from our pipelines is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline.

Income Taxes

Income Taxes

We provide for income taxes using the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The evaluation of a tax position is a two-step process. The first step is a recognition process whereby the Company determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

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

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1. Organization

6 Months Ended

Jun. 30, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Company Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”), a Delaware corporation, was formed in 1986 as a holding company and conducts substantially all of its operations through its wholly-owned subsidiaries.  Our operating subsidiaries include:

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

-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 (inactive); and

-Petroport, Inc., a Delaware corporation (inactive).

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,545,690	2,098,390
Common stock, shares outstanding	10,545,690	2,098,390

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11. Asset Retirement Obligations

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

We have asset retirement obligations associated with the future abandonment, dismantlement and removal of our pipelines and facilities and our oil and gas properties.  The following table summarizes our asset retirement obligation related to our pipelines and facilities and oil and gas properties:

Fair value of asset retirement obligations at February 15, 2012	$	1,294,139
Liabilities incurred		-
Liabilities settled		(3,685	)
Accretion expense		65,460
Asset retirement obligations as of June 30, 2012		1,355,914
Less:  current portion of asset retirement obligations		149,271
Asset retirement obligations, long-term balance
at June 30, 2012	$	1,206,643

Management has concluded that there is no legal or contractual obligation to dismantle or remove our refinery and facilities assets. Management further believes that our refinery and facilities assets have indeterminate lives under ASC guidance for estimating asset retirement obligations 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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Aug. 13, 2012
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
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		10,545,690
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2012

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12. Long-Term Debt

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Long-Term Debt

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

	June 30,		December 31,
	2012		2011
Refinery Loan	$	9,315,826	$	9,669,173
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		7,572,040		3,319,193
Captial Leases		2,933		6,237
		18,190,799		14,294,603
Less: Current portion of long-term debt		1,846,812		1,839,501
	$	16,343,987	$	12,455,102

Refinery Loan.  In September 2008, LE obtained a loan payable to First International Bank (which, together with its successors in interest, are referred to as “FIB”) under a promissory note in the amount of $10,000,000 (the “Refinery Loan”). The Refinery Loan, which is currently in default, accrues interest at a rate of prime plus 2.25% and has a maturity date of October 2028.  The Refinery Loan is: (i) secured by a first lien on the refinery and general assets of LE and (ii) subject to certain restrictive financial covenants related to debt to net worth and current ratio.  Interest was accrued on the Refinery Loan in the amount of $1,179,831 and $967,567 at June 30, 2012 and December 31, 2011, respectively.

In August 2011, LE entered into a Forbearance Agreement with FIB (the “Refinery Loan Forbearance Agreement”) that provided for a reduced minimum monthly payment of $60,000. The initial forbearance period under the Refinery Loan Forbearance Agreement was one year (the “Initial Forbearance Period”).  The Refinery Loan Forbearance Agreement provided for an additional one year extension period beyond the Initial Forbearance Period to August 12, 2013 (the “Extended Forbearance Period”), if we satisfied certain forbearance extension conditions (the “Forbearance Extension Conditions”) within the Initial Forbearance Period, as follows:

●   FIB must have received payments in the amount of either the tank storage fee or regular monthly payment, as applicable, during each of the 12 months of the Initial Forbearance Period;

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

●   The Nixon Facility must have been operational and generating gross profits to the extent that FIB was receiving not only regular monthly payments, but also payments of its 50% portion of the LE profit share (as determined under the Joint Marketing Agreement) in reduction of some portion of the arrearage.

During the Initial Forbearance Period and any Extended Forbearance Period and any extensions thereof, we remain subject to the terms, conditions and covenants of the Refinery Loan, other than those that qualified as existing defaults at the time we entered into the Refinery Loan Forbearance Agreement.  Further, FIB can terminate the Refinery Loan Forbearance Agreement and any extensions thereof at any time if any termination events (the “Termination Events”) occur, as follows:

●   We do not, upon the Nixon Facility becoming operational, and the cessation of the payment of tank storage fees by Genesis to us, make a monthly payment in the amount of $69,443 to FIB each month;

●   There is a default  under the Refinery Loan (other than the existing default) that is not cured within 30 days subject to certain extensions;

●   There is a default under the Refinery Loan Forbearance Agreement, the Construction and Funding Agreement, the Joint Marketing Agreement or the Crude Oil Supply and Throughput Services Agreement between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”) and such default continues for 10 days after its occurrence; or

●   LE files for bankruptcy protection or takes part in any other insolvency proceeding, seeks relief under any debtor relief law or had a receiver or similar official appointed.

In October 2011, FIB was acquired by American First National Bank (“AFNB”), which became the holder of the Refinery Loan.  In June 2012, AFNB sent a letter to the borrower and guarantors of the Refinery Loan (the “Borrowers”) outlining what AFNB believed to be contraventions to certain provisions of the Refinery Loan, the Refinery Loan Forbearance Agreement, the Deed of Trust and the Security Agreement, including an assertion that the merger between Blue Dolphin and LE represented a change of control of LE.  The Borrowers responded to AFNB expressing a belief that they are in compliance with provisions of the Refinery Loan, the Refinery Loan Forbearance Agreement, the Deed of Trust and the Security Agreement.

As of the date of filing of this report, management believes that we have satisfied the Forbearance Extension Conditions and no Termination Events have occurred.  If the Refinery Loan Forbearance Agreement is rightfully terminated, AFNB may demand payment of all of the amounts owed under the Refinery Loan and commence foreclosure proceedings, which would result in a material adverse effect on us.

Once all past due principal, interest, costs, fees and taxes have been paid under the Refinery Loan Forbearance Agreement, LE is required to resume payments of $83,333.33 per month for a period of 12 consecutive months to AFNB in order to replenish the $1.0 million payment reserve required by the Refinery Loan.  After all past due principal and interest (as well as costs, fees and taxes) have been paid, the Refinery Loan will be re-amortized and will have a maturity date of October 1, 2028.

Notre Dame Debt.  LE obtained a loan in the original amount of $8,000,000 pursuant to a promissory note previously held by Notre Dame Investors, Inc. and currently held by John Kissick (the “Notre Dame Debt”). The note, which is currently in default, accrues interest at the default rate of 16% and is secured by a second lien on the refinery and general assets of LE.  Interest was accrued on the note in the amount of $753,929 and $650,214 at June 30, 2012 and December 31, 2011, respectively.

In August 2011, LE entered into an intercreditor and subordination agreement under which Mr. Kissick, as second lienholder on the Nixon Facility, agreed to forebear his rights under the note evidencing the Notre Dame Debt for so long as amounts are outstanding on our more senior construction funding obligations. Further, in a letter agreement in August 2011, Mr. Kissick confirmed, acknowledged and agreed not to institute a suit or other proceeding against LE to foreclose upon any liens that have been established pursuant to the Notre Dame Debt or exercise any other rights or remedies pursuant to the promissory note under applicable law or otherwise so long as the Joint Marketing Agreement is in effect and has not been terminated.  The Joint Marketing Agreement expires in August 2014.

As of June 30, 2012, the Joint Marketing Agreement was in effect and had not been terminated. There are no financial covenants associated with this debt.

Construction and Funding Agreement.  In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations. Payments commenced in the first quarter of 2012.  Interest accrues at the rate of 6%.  Interest was accrued on the financing in the amount of $182,829 and $23,578 at June 30, 2012 and December 31, 2011, respectively.  There are no financial covenants associated with this obligation.

See Note (17), “Subsequent Events” and “Management’s Discussion and Analysis of Financial Condition –  Clarification of Amounts Owed to Genesis and its Affiliates” in Item 2 of this report for additional disclosures related to amendments to the Joint Marketing Agreement that add to our obligation amount under the Construction and Funding Agreement.

Capital Leases.  LE was obligated under various capital lease agreements for equipment totaling $2,933 and $6,237 at June 30, 2012 and December 31, 2011, respectively.  The capital leases require monthly payments ranging from $164 to $2,559, including imputed interest at rates ranging from 8.50% to 13.39%, and maturing at various dates through February 2014.  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.

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

	June 30,		December 31,
	2012		2011
Cost	$	9,396	$	9,396
Less:  Accumulated amortization		4,071		3,602
	$	5,325	$	5,794

Amortization on assets under capital leases is included in depletion, depreciation and amortization expense in the condensed consolidated statements of operations and was $235 and $1,456 for the three months ended June 30, 2012 and 2011, respectively, and $470 and $2,911 for the six months ended June 30, 2012 and 2011, respectively.

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUE FROM OPERATIONS
Refined product sales	$ 84,416,296		$ 130,187,259
Pipeline operations	124,476		194,386
Oil and gas sales	250,081		450,421
Total revenue from operations	84,790,853		130,832,066
COST OF OPERATIONS
Cost of refined products sold	88,051,229		133,692,455
Refinery operating expenses	2,239,914		3,302,665
Pipeline operating expenses	127,502		237,120
Lease operating expenses	298,962		500,675
Depletion, depreciation and amortization	520,390	4,306	798,352	8,614
General and administrative expenses	734,720	177,112	1,260,307	290,940
Accretion expense	41,685		65,460
Total cost of operations	92,014,402	181,418	139,857,034	299,554
Loss from operations	(7,223,549)	(181,418)	(9,024,968)	(299,554)
OTHER INCOME (EXPENSE)
Net tank rental revenue	81,364	353,709	175,319	696,454
Interest and other income	2,265	295	3,915	6,389
Interest expense	(275,333)	(12,061)	(508,850)	(24,372)
Unrealized gain (loss) on derivatives
Total other income (expense)	(191,704)	341,943	(329,616)	678,471
Income (loss) before income taxes	(7,415,253)	160,525	(9,354,584)	378,917
Income tax benefit (expense)	17,419		(13,144)
Net income (loss)	$ (7,397,834)	$ 160,525	$ (9,367,728)	$ 378,917
Income (loss) per common share:
Basic	$ (0.70)	$ 160,525	$ (1.18)	$ 378,917
Diluted	$ (0.70)	$ 160,525	$ (1.18)	$ 378,917
Weighted average number of common shares outstanding:
Basic	10,541,853	1	7,916,129	1
Diluted	10,541,853	1	7,916,129	1

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6. Refined Products Inventory Risk Management

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Products Inventory Risk Management

Under our refined products inventory risk management policy Genesis may, but is not required to, use gasoline and distillate 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 condensed consolidated balance sheets and the related net gain or loss is recorded within cost of refined products sold in the condensed 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. At June 30, 2012, we had open commodity instruments consisting of refined product futures on 22,000 net barrels to protect the value of certain refined product and blendstock inventories. The fair value of the outstanding contracts at June 30, 2012 was a net unrealized loss of approximately $127,000 comprised of short-term unrealized losses, which is reflected within accrued expenses and other current liabilities in the condensed consolidated balance sheets. At December 31, 2011, there were no commodity instruments with open positions.

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 products when our inventory levels exceed targeted levels (currently 1.5 days production).  Although the decision to enter into a futures contract is made solely by Genesis, Genesis typically confers with management as part of 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 June 30, 2012, we had the following outstanding obligation based on futures contracts of refined products that were entered into as economic hedges, through Genesis. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousand barrels):

	Notional Contract Volumes by Year of Maturity
	2012		2013		2014		2015
Inventory positions (futures):
Refined products - net short (long) positions		22		-		-		-

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5. Fair Value Measurement

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

We are subject to the gain or loss on financial assets based on our various agreements and understandings with Genesis.  Pursuant to these agreements and understandings, Genesis can execute, on our behalf, the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity risks associated with our refined products inventory and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil inputs.  Based on our agreements with Genesis, we are liable for any gains or losses associated with the purchase and/or sale of such financial instruments on our behalf by Genesis and such instruments represent embedded derivatives for the purpose of financial reporting.  Accordingly, 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 June 30, 2012 and December 31, 2011 due to their short-term maturities. The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2012 and the basis for that measurement:

			Fair Value Measurement at June 30, 2012 Using
	Carrying Value as at June 30, 2012		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Financial liabilties:
Commodity contracts	$	126,983	$	126,983	$	-	$	-

Carrying amounts of commodity contracts executed by Genesis are reflected as financial liabilities in accrued expenses and other current liabilities in the condensed consolidated balance sheets.

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17. Subsequent Events

6 Months Ended

Jun. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

Amendments to Nixon Facility Operating Agreements

In July and August 2012, we entered into certain amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that any Deficit Amounts will be added to the obligation amount under the Construction and Funding Agreement.  In May and June 2012, Deficit Amounts were added to our obligation amount under the Construction and Funding Agreement as a result of losses we incurred. In addition, the parties agreed that the priority of payments be amended 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, however, that we will not participate in available funds until any Deficit Amounts added to the Construction and Funding Agreement are paid in full.  AFNB received a payment in the amount of $139,420 in August 2012 in respect of its ratable share of available funds generated in July 2012.

As of June 30, 2012, total advances under the Construction and Funding Agreement were approximately $7.6 million.  Pursuant to amendments and clarifications to the Joint Marketing Agreement, Deficit Amounts of approximately $4.3 million are included in our accounts payable at June 30, 2012.  Subsequent to the end of the quarter, we paid approximately $1.8 million of the Deficit Amounts.

Refinery Loan Forbearance Agreement Extension

LE entered into the Refinery Loan Forbearance Agreement in August 2011.  The Refinery Loan Forbearance Agreement provided for an Extended Forbearance Period to August 2013 if we satisfied the Forbearance Extension Conditions within the Initial Forbearance Period.  As of the date of this report, management believes we have satisfied the Forbearance Extension Conditions within the Initial Forbearance Period.

Lawsuit and Settlement Agreement

Pursuant to an Order of Nonsuit and Dismissal with Prejudice, a presiding judge ordered, adjudged and decreed that counter-plaintiff LEH’s claims and causes of action in the Lawsuit were dismissed on July 6, 2012.

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13. Income Taxes

6 Months Ended

Jun. 30, 2012

Income Tax Disclosure [Abstract]

Income Taxes

As a result of the Acquisition, Section 382 of the Internal Revenue code imposes potential limitations on the use of our NOL carryovers.  The amount of NOL subject to such limitations is approximately $19.7 million.  The NOL generated subsequent to the Acquisition, approximately $9.9 million, is not subject to any such limitation.  For the three and six months ended June 30, 2012, we did not recognize any deferred tax asset related to such NOL’s due to the uncertainty of its use.

LE is an LLC and prior to the Acquisition its taxable income or loss flowed through to its individual 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.  On Acquisition, LE became the legal subsidiary of Blue Dolphin and LE’s taxable income or loss flows through to Blue Dolphin for federal and state income tax purposes.  As a result of the Acquisition, Section 382 of the Internal Revenue Code imposes a limitation on the use Blue Dolphin’s NOLs.  For the three months ended June 30, 2012, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty to the realization of our NOLs.

The State of Texas has a business tax that is imposed on gross margin revenue to replace its prior franchise tax regime. Although the Texas margins tax (“TMT”) is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of the tax make it similar to an income tax.  At June 30, 2012, we accrued $13,144 in TMT

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9. Accounts Payable, Related Party Transactions

6 Months Ended

Jun. 30, 2012

Payables and Accruals [Abstract]

Accounts Payable, Related Party Transactions

As part of the Acquisition, LEH, which owns 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 based on revenues from the sale of diesel blend stocks processed by the Nixon Facility 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 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 between LE and GEL Tex Marketing, LLC (“GEL”) dated August 12, 2011(the “Joint Marketing Agreement”), which has an initial term of three years and year-to-year renewals at the option of either party thereafter, (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.

Herbert N.Whitney, a member of the Board, currently serves as a consultant to LEH.

 Aggregate amounts expensed for Services for the three and six months ended June 30, 2012 were $2,239,914 (approximately $2.85 per barrel) and $3,302,665 (approximately $2.85 per barrel), respectively.  At June 30, 2012 and December 31, 2011, the amounts outstanding to LEH for Services were $1,028,817 and $908,140, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets.  LE related party payable was converted to LE’s members’ equity in the amount of $993,732 on Acquisition.

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7. Inventories

6 Months Ended

Jun. 30, 2012

Inventory Disclosure [Abstract]

Inventories

Inventory balances consisted of the following:

	June 30,		December 31,
	2012		2011
Low-sulfur diesel	$	445,857	$	2,193,864
Naphtha		2,759,078		1,067,011
Atmospheric gas oil		400,445		1,010,877
Other liquids		55,068		64,486
Propane		43,877		59,599
Crude		74,209		134,289
Supplies		-		3,835
	$	3,778,534	$	4,533,961

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8. Property, Plant and Equipment, Net

6 Months Ended

Jun. 30, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property and equipment consisted of the following:
 

	June 30,		December 31,
	2012		2011
Refinery and facilities	$	33,784,022	$	-
Oil and gas properties (full-cost method)		5,144,973		-
Pipelines and facilities		9,223,836		-
Onshore separation and handling facilities		325,435		-
Land		577,965		104,740
Other property and equipment		521,630		217,136
		49,577,861		321,876
Less:  Accumulated depletion, depreciation and amortization		855,084		62,443
		48,722,777		259,433
Construction in Progress		314,995		32,048,496
Property, Plant and Equipment, Net	$	49,037,772	$	32,307,929

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10. Note Payable

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Note Payable

In January 2010, LE issued a $100,000 short-term note as payment for financing costs.  The balance on this note was $31,317 and $46,318 at June 30, 2012 and December 31, 2011, respectively.  The unsecured note, which bears interest at 10% and was originally due in January 2012, has been extended to December 2012.

In March 2012, LE acquired two used trucks for use at the Nixon Facility under a short-term note payable.  The balance on this note was $12,075 at June 30, 2012.  The unsecured note bears interest at 5%.

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16. Stock Options (Tables)

6 Months Ended

Jun. 30, 2012

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

Stock options activity table

	Shares	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Aggregate Intrinisic Value
Options outstanding at December 31, 2011	28,887	$13.29
Options granted	-	$   -
Options exercised	-	$   -
Options expired or cancelled	(2,485)	$   -
Options outstanding at June 30, 2012	26,402	$13.30	1.4	$            -
Options exercisable at June 30, 2012	26,402	$13.30	1.4	$            -

Stock options outstanding

	Options Outstanding			Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price	Number Exercisable	Weighted Average Exercise Price
$2.45 to $5.60	10,118	0.8	$3.06	10,118	$3.06
$13.30 to $19.67	16,284	1.8	$19.67	16,284	$19.67
	26,402	1.4	$13.30	26,402	$13.30

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15. Earnings per share (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income (loss) per common share:
Net income (loss)	$ (7,397,834)	$ 160,525	$ (9,367,728)	$ 378,917
Basic and diluted
Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,541,853	1	7,916,129	1
Per share amount	$ (0.70)	$ 160,525	$ (1.18)	$ 378,917

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15. Earnings Per Share

6 Months Ended

Jun. 30, 2012

Income (loss) per common share:

Earnings Per Share

We apply the provisions of the ASC guidance for computing earnings per share.  The guidance requires the presentation of basic earnings per share (“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 condensed 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 shareholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue common stock were converted to common stock that then shared in the earnings of the entity. Given our net loss, diluted EPS excludes stock options outstanding as they would be anti-dilutive.

For the three and six months ended June 30, 2012, the weighted average number of common shares is computed as LE’s number of common shares outstanding from the beginning of the period to the date of the Acquisition date combined with Blue Dolphin’s number of common shares outstanding from the date of the Acquisition to the end of the period.  For the three months and six months ended June 30, 2011, the weighted average number of common shares is computed as LE’s number of common shares outstanding, which was one member unit.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012			2011		2012			2011
Net income (loss)	$	(7,397,834	)	$	160,525	$	(9,367,728	)	$	378,917
Basic and Diluted
Weighted average number of shares of common
stock outstanding and potential dilutive shares
of common stock		10,541,853			1		7,916,129			1
Per share amount	$	(0.70	)	$	160,525	$	(1.18	)	$	378,917

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4. Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Business segment reporting

	Three Months Ended June 30, 2012
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

Following is a reconciliation of our EBIT (by business segment) for the three months ended June 30, 2011, and at June 30, 2011:

	Three Months Ended June 30, 2011
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

	Six Months Ended June 30, 2012
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

Following is a reconciliation of our EBIT (by business segment) for the six months ended June 30, 2011, and at June 30, 2011:

	Six Months Ended June 30, 2011
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

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12. Long-Term Debt (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Debt Disclosure [Abstract]
Refinery loan accrued interest	$ 1,179,831		$ 1,179,831		$ 967,567
Notre Dame debt accrued interest	753,929		753,929		650,214
Construction funding accrued interest	182,829		182,829		23,578
Capital leases	2,933		2,933		6,237
Capital lease depletion, depreciation and amortization expense	$ 235	$ 1,456	$ 470	$ 2,911

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6. Refined Products Inventory Risk Management (Details Narrative) (USD $)	Jun. 30, 2012 Integer
Refined Products Inventory Risk Management Details Narrative
Refined products - net short (long) positions	22,000
Fair value of outstanding contracts	$ (127,000)

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
OPERATING ACTIVITIES
Net income (loss)	$ (9,367,728)	$ 378,917
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	792,642	8,615
Unrealized loss on derivatives	126,983
Amortization of debt issue costs	16,899	16,899
Amortization of intangible assets	5,710
Accretion expense	65,460
Common stock issued for services	119,000
Changes in operating assets and liabilities (net of effects of Acquisition in 2012)
Restricted cash	(538)	(589)
Accounts receivable	(5,589,773)
Prepaid expenses and other current assets	106,442
Deposits	(775,921)	(68,407)
Inventory	810,594	(1,698)
Abandonment costs incurred	(3,685)
Accounts payable, accrued expenses and other liabilities	8,654,107	14,613
Accounts payable, related party	2,022,546	183,419
Net cash provided by (used in) operating activities	(3,017,262)	531,769
INVESTING ACTIVITIES
Capital expenditures	(2,074,137)	(505,670)
Cash acquired on Acquisition	1,674,594
Net cash provided by (used in) investing activities	(399,543)	(505,670)
FINANCING ACTIVITIES
Proceeds from issuance of debt	4,759,393
Payments on long term debt	(847,197)	(21,066)
Payments on notes payable	(18,925)	(5,034)
Net cash provided by (used in) financing activities	3,893,271	(26,100)
Net increase (decrease) in cash and cash equivalents	476,466	(1)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,822	733
CASH AND CASH EQUIVALENTS AT END OF PERIOD	478,288	732
Non-cash investing and financing activities:
Financing of insurance premiums	82,560
Related party payable converted to equity	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	$ 20,000

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4. Business Segment Information

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Business Segment Information

We are engaged in three lines of business: (i) ownership of crude oil and condensate processing assets, (ii) pipeline transportation services to producers/shippers and (iii) oil and gas exploration and production.  Our primary assets include the Nixon Facility, oil and natural gas pipelines in the Gulf of Mexico region and oil and natural gas leasehold interests in the U.S. Gulf of Mexico and the North Sumatra Basin offshore Indonesia.

Management uses earnings before interest expense and income taxes (“EBIT”), 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 EBIT is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by management.  EBIT 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 expense (or income). 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 EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income (loss) and other performance measures such as operating cash flows.

Following is a reconciliation of our EBIT (by business segment) for the three months ended June 30, 2012, and at June 30, 2012:

	Three Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	84,416,296		$	124,476		$	250,081		$	-		$	84,790,853
Operation cost(2)		90,369,807			241,503			503,922			378,780			91,494,012
Depletion, depreciation
and amortization		292,206			167,254			57,361			3,569			520,390
Other non-interest income		81,364			-			-			-			81,364
EBIT	$	(6,164,353	)	$	(284,281	)	$	(311,203	)	$	(382,349	)	$	(7,142,185	)
Capital expenditures	$	724,805		$	-		$	-		$	-		$	724,805
Identifiable assets(3)	$	44,975,160		$	11,969,394		$	5,451,217		$	1,014,185		$	63,409,956

___________________

(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 the economic hedges on our refined products, executed by Genesis, is included within operation cost of our Crude Oil and Condensate Processing group.  Cost of refined products sold includes a realized loss of $1,601 and an unrealized loss of $126,983 for the three months ended June 30, 2012.

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

Following is a reconciliation of our EBIT (by business segment) for the three months ended June 30, 2011, and at June 30, 2011:

	Three Months Ended June 30, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenues	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		177,112		-		-		-		177,112
Depletion, depreciation
and amortization		4,306		-		-		-		4,306
Other non-interest income		353,709		-		-		-		353,709
EBIT	$	172,291	$	-	$	-	$	-	$	172,291
Capital expenditures	$	289,212	$	-	$	-	$	-	$	289,212
Identifiable assets(3)	$	30,320,141	$	-	$	-	$	-	$	30,320,141

________________

(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.

Following is a reconciliation of our EBIT (by business segment) for the six months ended June 30, 2012, and at June 30, 2012:

	Six Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	130,187,259		$	194,386		$	450,421		$	-		$	130,832,066
Operation cost(2)		137,232,245			437,220			892,798			496,419			139,058,682
Depletion, depreciation		-			-			-			-
and amortization		487,110			225,554			79,570			6,118			798,352
Other non-interest income		175,319			-			-			-			175,319
EBIT	$	(7,356,777	)	$	(468,388	)	$	(521,948	)	$	(502,537	)	$	(8,849,649	)
Capital expenditures	$	2,074,137		$	-		$	-		$	-		$	2,074,137
Identifiable assets(3)	$	44,975,160		$	11,969,394		$	5,451,217		$	1,014,185		$	63,409,956

_______________

(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 the economic hedges on our refined products, executed by Genesis, is included within operation cost of our Crude Oil and Condensate Processing group. Cost of refined products sold includes a realized loss of $1,601 and an unrealized loss of $126,983 for the six months ended June 30, 2012.

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

Following is a reconciliation of our EBIT (by business segment) for the six months ended June 30, 2011, and at June 30, 2011:

	Six Months Ended June 30, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenues	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		290,940		-		-		-		290,940
Depletion, depreciation		-		-		-		-
and amortization		8,614		-		-		-		8,614
Other non-interest income		696,454		-		-		-		696,454
EBIT	$	396,900	$	-	$	-	$	-	$	396,900
Capital expenditures	$	505,670	$	-	$	-	$	-	$	505,670
Identifiable assets(3)	$	30,320,141	$	-	$	-	$	-	$	30,320,141

________________

(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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5. Fair Value Measurement (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

			Fair Value Measurement at June 30, 2012 Using
	Carrying Value as at June 30, 2012		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Financial liabilties:
Commodity hedging contracts		$         126,983	$              126,983	$                         -	$                      -

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4. Business Segment Information (Details) (USD $)

3 Months Ended

6 Months Ended

Jun. 30, 2012

Jun. 30, 2011

Jun. 30, 2012

Jun. 30, 2011

Business segment reporting

	Three Months Ended June 30, 2012
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

Following is a reconciliation of our EBIT (by business segment) for the three months ended June 30, 2011, and at June 30, 2011:

	Three Months Ended June 30, 2011
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

	Six Months Ended June 30, 2012
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

⁽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.

Following is a reconciliation of our EBIT (by business segment) for the six months ended June 30, 2011, and at June 30, 2011:

	Six Months Ended June 30, 2011
	Segment
	Crude Oil		Oil and Gas
	and Condensate	Pipeline	Exploration &	Corporate &
	Processing	Transportation	Production	Other(1)	Total
Revenues	$               -	$               -	$               -	$               -	$               -
Operation cost(2)	-	-	-	-	-
Depletion, depreciation
and amortization	-	-	-	-	-
Other non-interest income	-	-	-	-	-
EBIT	$               -	$               -	$               -	$               -	$               -
Capital expenditures	$               -	$               -	$               -	$               -	$               -
Identifiable assets(3)	$               -	$               -	$               -	$               -	$               -

Crude Oil And Condesate Processing

Statement [Line Items]

Revenues

$ 84,416,296

$ 130,187,259

Operation cost

90,369,807

177,112

137,232,245

290,940

Depletion, depreciation and amortization

292,206

4,306

487,110

8,614

Other non-interest income

81,364

353,709

175,319

696,454

EBIT

(6,164,353)

172,291

(7,356,777)

396,900

Capital expenditures

724,805

289,212

2,074,137

505,670

Identifiable assets

44,975,160

30,320,141

44,975,160

30,320,141

Pipeline Transportation

Statement [Line Items]

Revenues

124,476

194,386

Operation cost

241,503

437,220

Depletion, depreciation and amortization

167,254

225,554

Other non-interest income

EBIT

(284,281)

(468,388)

Capital expenditures

Identifiable assets

11,969,394

11,969,394

Oil And Gas Exploration and Production

Statement [Line Items]

Revenues

250,081

450,421

Operation cost

503,922

892,798

Depletion, depreciation and amortization

57,361

79,570

Other non-interest income

EBIT

(311,203)

(521,948)

Capital expenditures

Identifiable assets

5,451,217

5,451,217

Corporate and Other

Statement [Line Items]

Revenues

Operation cost

378,780

496,419

Depletion, depreciation and amortization

3,569

6,118

Other non-interest income

EBIT

(382,349)

(502,537)

Capital expenditures

Identifiable assets

1,014,185

1,014,185

Total

Statement [Line Items]

Revenues

84,790,853

130,832,066

Operation cost

91,494,012

177,112

139,058,682

290,940

Depletion, depreciation and amortization

520,390

4,306

798,352

8,614

Other non-interest income

81,364

353,709

175,319

696,454

EBIT

(7,142,185)

172,291

(8,849,649)

396,900

Capital expenditures

724,805

289,212

2,074,137

505,670

Identifiable assets

$ 63,409,956

$ 30,320,141

$ 63,409,956

$ 30,320,141

XML

14. Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Genesis Agreements

We are highly 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 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 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.  After the expiration of its initial term, the Crude Supply Agreement automatically renews for successive one year terms unless either party notifies the other party of its election to terminate the Crude Supply Agreement within 90 days of the expiration of the then current term.

●   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, in their discretion, 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 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 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 deficiency amount, which shall accrue interest (the “Deficiency Amount”).  If there is a Deficiency Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficiency 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 for a breach or upon termination of the Refinery Loan Forbearance Agreement. If Milam terminates the Construction and Funding Agreement, then: (i) Milam and LE are required to execute a forbearance agreement, the form of which has been previously agreed to, pursuant to which LE will pay Milam a fee of $150,000 per month in order to maintain the forbearance (such amount shall be credited against the amount owed) for a period of six months (during which time Milam will agree not to foreclose pursuant to the Construction and Funding Agreement and, thus, LE has the right to find financing to pay off such amounts), (ii) Milam shall be entitled to receive payment in full for all obligations owed under the Construction and Funding Agreement, (iii) all liens in favor of Milam will remain in full force and effect until released in accordance with the terms of the Construction and Funding Agreement and (iv) upon repayment of all obligations owed to Milam pursuant to the terms of the forbearance agreement executed by Milam and LE, LE shall have no further obligations to Milam or its affiliates under the Construction and Funding Agreement; and

●   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, 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”), $150,000 (the “Base Construction Payment”) 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 ever a deficiency (i.e., Gross Profits is less than $150,000 in a month) until any such deficiencies have been satisfied in full.

(b)   Second, prior to and as of the Investment Threshold Date, LE shall generally receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) based on revenues from the sale of diesel blendstocks processed by the Nixon Facility 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 Deficiency Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficiency 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 and the Operations Payments to be paid to GEL and LE respectively, 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 the forbearance agreement with a bank, then 50% of the LE Profit Share shall be directly remitted by GEL to the bank until such forbearance amount is paid in full; and provided further that, if there is a shortfall in any month with respect to payments due under the Construction and Funding Agreement (the “Deficit Amount”) outstanding 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: GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share, and 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.  After the expiration of its initial term, the Joint Marketing Agreement shall be automatically renewed for successive one year terms unless either party notifies the other party of its election to terminate the Joint Marketing Agreement within 90 days of the expiration of the then current term.  The Joint Marketing Agreement also provides that it may be terminated prior to the end of its then current term under certain circumstances.

●   Amendments and Clarifications to the Joint Marketing Agreement -- The Joint Marketing Agreement has been amended and clarified to provide for Operating Expenses being paid by GEL to LE during the months of July and August 2012 as a result of amounts owed for crude oil costs and losses sustained by LE during the months in which total revenue from the sale of refined products was not sufficient.

See “Management’s Discussion and Analysis of Financial Condition – Relationship with Genesis” in Item 2 of this report for additional disclosures related to the Genesis Agreements.

See Note (17), “Subsequent Events” and “Management’s Discussion and Analysis of Financial Condition – Clarification of Amounts Owed to Genesis and its Affiliates” in Item 2 of this report for additional disclosures related to amendments to the Joint Marketing Agreement that add to our obligation amount under the Construction and Funding Agreement.

Ingleside Refinery Option

In June 2012, we entered into a Letter Agreement (the “Letter Agreement”) to purchase a 180 day option to acquire an idled refinery located in Ingleside, Texas (”Ingleside”) from LEH, Blue Dolphin’s largest shareholder.  Ingleside is currently owned by Lazarus Texas Refinery I, LLC, a Delaware limited liability company and a wholly-owned subsidiary of LEH (“LTRI”).

Pursuant to the terms of the Letter Agreement, we paid LEH a fully refundable sum of $100,000 cash as consideration for the option. If we choose to exercise the option, we will acquire all the outstanding interests of LTRI for cash or a note payable or a combination of the two.  Further, under the terms of any Purchase and Sale Agreement entered into by the parties: (a) we will assume all outstanding liabilities associated with Ingleside, (b) we will reimburse the costs of LTRI and LEH associated with the acquisition, refurbishment and environmental remediation of Ingleside, and (c) LEH will credit the full amount of the option consideration towards the purchase price.

If Blue Dolphin and LEH are unable to negotiate and execute a Purchase and Sale Agreement with mutually acceptable terms, including purchase price, within the timeframe of the option, LEH is obligated to return the option consideration to Blue Dolphin.  Further, if after the Environmental Protection Agency has approved the remediation cleanup of Ingleside, there is a difference between the amount spent by LEH to remediate environmental issues at Ingleside and what Blue Dolphin is willing to pay to acquire the interests of LTRI, then LEH will return the option consideration to Blue Dolphin.

Certain of the Ingleside assets are currently subject to a Lease Agreement (the “Lease Agreement”) with Superior Crude Gathering, Inc., a Texas corporation (“Superior”).  If Blue Dolphin chooses to exercise the option, then any cash consideration that must be paid to Superior in connection with the termination of the Lease Agreement would be the responsibility of Blue Dolphin.

Management Agreement

See Note (9), “Accounts Payable, Related Party Transactions” of this report for additional disclosures related to the Management Agreement.

Legal Matters

Pursuant to a Settlement Agreement and Mutual Release dated February 15, 2012 (the “Settlement Agreement”), by and among Blue Dolphin, LEH and Lazarus Louisiana Refinery II, LLC (“LLRII”), the parties agreed to settle and compromise all disputes between them in connection with closing of the Acquisition.  LEH agreed to file a non-suit with prejudice of all pending claims against Blue Dolphin under Cause No. 210-32561, styled Blue Dolphin Energy Company v. Lazarus Energy Holdings, L.L.C. and Lazarus Louisiana Refinery II, L.L.C., in the 129th District Court of Harris County, Texas (the “Lawsuit”).  Blue Dolphin agreed that it will not execute or attempt to execute on an order that was signed on May 16, 2011 in the Lawsuit severing LEH’s counterclaims into Cause No. 2010-32561-A, which resulted in a Partial Summary Judgment becoming a final judgment in Blue Dolphin’s favor.

See Note (17), “Subsequent Events,” for additional disclosures related to the Lawsuit and Settlement Agreement.

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business.  During the second quarter of 2012, a vendor placed a mechanic’s lien on the Nixon Facility as protection during construction activities. As described further under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources,” management is executing a liquidity plan to address outstanding payables due to third-parties, although there can be no assurance that the liquidity plan will be successful.  Management does not believe that the lien will have a material adverse effect on our results of operations.

Environmental Matters

Our operations are subject to extensive and periodically changing federal and state environmental regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities.   Our policy is to accrue environmental and clean-up related costs of a non-capital nature when it is probable that a liability has been incurred and the amount can be reasonably estimated. Such estimates may be subject to revision in the future as regulations and other conditions change.

Periodically, we receive communications from various federal, state and local governmental authorities asserting violations of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. We intend to respond in a timely manner to all such communications and to take appropriate corrective actions. We do not anticipate that any such matters currently asserted will have a material adverse impact on our consolidated financial condition, results of operations or cash flows.