10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended:  March 31, 2013

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

For the transition period from _____________ to_____________

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

(713) 568-4725

(Registrant’s telephone number, including area code)

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Number of shares of common stock, par value $0.01 per share issued as of May 15, 2013:  10,571,629

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

FORM 10-Q REPORT INDEX

PART I.  FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	3
	Condensed Consolidated Balance Sheets (Unaudited)	3
	Condensed Consolidated Statements of Operations (Unaudited)	4
	Condensed Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Condensed Consolidated Financial Statements (Unaudited)	6
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
ITEM 4.	CONTROLS AND PROCEDURES	42
PART II.  OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	43
ITEM 1A.	RISK FACTORS	43
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	43
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	43
ITEM 4.	MINE SAFETY DISCLOSURES	43
ITEM 5.	OTHER INFORMATION	43
ITEM 6.	EXHIBITS	44
	SIGNATURES	45

2

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	88,059		$	420,896
Restricted cash		27,348			89,593
Accounts receivable, net		10,510,790			15,398,755
Prepaid expenses and other current assets		208,959			228,314
Deposits		1,245,910			1,236,447
Inventory		3,789,792			2,300,692
Total current assets		15,870,858			19,674,697
Total property and equipment, net		36,063,523			35,862,085
Debt issue costs, net		523,885			532,335
Other assets		-			9,463
Trade name		303,346			303,346
TOTAL ASSETS	$	52,761,612		$	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	16,292,668		$	19,171,013
Accounts payable, related party		2,178,061			1,594,021
Note payable		9,348,518			43,941
Asset retirement obligations, current portion		90,601			-
Accrued expenses and other current liabilities		895,202			725,238
Interest payable, current portion		637,551			640,352
Long-term debt, current portion		1,485,000			1,816,960
Total current liabilities		30,927,601			23,991,525
Long-term liabilities:
Asset retirement obligations, net of current portion		855,823			921,260
Long-term debt, net of current portion		4,960,584			13,989,517
Long-term interest payable, net of current portion		910,071			858,784
Total long-term liabilities		6,726,478			15,769,561
TOTAL LIABILITIES		37,654,079			39,761,086
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,571,629 and 10,563,297		105,717			105,633
shares issued at March 31, 2013 and December 31, 2012, respectively)
Additional paid-in capital		36,574,059			36,524,142
Accumulated deficit		(20,772,243	)		(20,008,935	)
Treasury stock, 150,000 and 0 shares, respectively, at cost		(800,000	)		-
Total stockholders' equity		15,107,533			16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	52,761,612		$	56,381,926

See accompanying notes to condensed consolidated financial statements.

3

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended March 31,
	2013			2012
REVENUE FROM OPERATIONS
Refined product sales	$	109,171,507		$	45,770,963
Pipeline operations		73,148			69,910
Oil and gas sales		-			6,056
Total revenue from operations		109,244,655			45,846,929
COST OF OPERATIONS
Cost of refined products sold		106,322,661			45,641,226
Refinery operating expenses		2,745,209			1,062,751
Pipeline operating expenses		45,371			109,618
Lease operating expenses		26,901			19,338
General and administrative expenses		484,564			525,587
Depletion, depreciation and amortization		328,788			255,753
Abandonment expense		27,451			-
Accretion expense		25,164			21,561
Total cost of operations		110,006,109			47,635,834
Loss from operations		(761,454	)		(1,788,905	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		278,350			93,955
Interest and other income		835			1,650
Interest expense		(281,063	)		(233,517	)
Total other expense		(1,878	)		(137,912	)
Loss from continuing operations before income taxes		(763,331	)		(1,926,817	)
Tax expense
Current		-			(30,563	)
Deferred		-			-
Income tax expense		-			(30,563	)
Loss from continuing operations, net of tax		(763,331	)		(1,957,380	)
Loss from discontinued operations, net of tax		-			(12,514	)
Net loss	$	(763,331	)	$	(1,969,894	)
Basic loss per common share
Continuing operations	$	(0.07	)	$	(0.21	)
Discontinued operations	$	-		$	-
Basic loss per common share	$	(0.07	)	$	(0.21	)
Diluted loss per common share
Continuing operations	$	(0.07	)	$	(0.21	)
Discontinued operations	$	-		$	-
Diluted loss per common share	$	(0.07	)	$	(0.21	)
Weighted average number of common shares outstanding:
Basic		10,510,334			9,476,748
Diluted		10,510,334			9,476,748

See accompanying notes to condensed consolidated financial statements.

4

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2013			2012
OPERATING ACTIVITIES
Net loss	$	(763,331	)	$	(1,969,894	)
Loss from discontinued operations		-			12,514
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		328,788			252,898
Unrealized loss on derivatives		52,050			-
Amortization of debt issue costs		8,450			8,449
Amortization of intangible assets		9,463			2,855
Accretion expense		25,164			21,561
Abandonment costs incurred		27,451			(110	)
Common stock issued for services		50,000			20,000
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash		62,245			(151	)
Accounts receivable		4,087,965			(15,923,454	)
Prepaid expenses and other current assets		19,355			(57,513	)
Deposits		(9,463	)		(667,421	)
Inventory		(1,489,100	)		(554,441	)
Accounts payable, accrued expenses and other liabilities		(2,739,371	)		16,010,675
Accounts payable, related party		584,040			1,253,764
Net cash provided by (used in) operating activities - continuing operations		253,705			(1,590,268	)
Net cash provided by operating activities - discontinued operations		-			11,909
Net cash provided by (used in) operating activities		253,705			(1,578,359	)
INVESTING ACTIVITIES
Capital expenditures		(530,226	)		(1,349,332	)
Cash acquired on acquisition		-			1,674,594
Net cash provided by (used in) investing activities		(530,226	)		325,262
FINANCING ACTIVITIES
Proceeds from issuance of debt		-			2,364,012
Payments on long-term debt		(60,876	)		(2,916	)
Proceeds from notes payable		15,031			-
Payments on notes payable		(10,472	)		-
Net cash provided by (used in) financing activities		(56,316	)		2,361,096
Net increase (decrease) in cash and cash equivalents		(332,837	)		1,107,999
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		420,896			1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	88,059		$	1,109,821
Supplemental Information:
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	$	800,000		$	-
Non-cash investing and financing activities
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
Shares issued for services	$	50,000		$	40,000

See accompanying notes to condensed consolidated financial statements.

5

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

 (1) Organization

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company. We are primarily an independent refiner and marketer of petroleum products.  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (6) Business Segment Information” for further discussion of our business segments.

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

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

● Lazarus Refining & Marketing, LLC (“LRM”), a Delaware limited liability company (petroleum storage and terminaling);

● 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 (“BDEX”), a Delaware corporation (exploration and production investment); and

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

 (2) Basis of Presentation

We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (14) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

 (3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

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

6

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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 $27,348 and $89,593 at March 31, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $0 and $170,896 at March 31, 2013 and December 31, 2012, respectively.

We had four customers that accounted for approximately 81% of our total revenue for the three months ended March 31, 2013. These four customers represented approximately $7.5 million of accounts receivable at March 31, 2013.

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

We utilize an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. 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.

7

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Property and Equipment

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are charged to expense as incurred. Management expects to continue making improvements to our refinery assets based on technological advances.

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012. The estimated fair values of our AROs related to our oil and gas properties were recorded at February 15, 2012 in connection with our acquisition of LE.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets for the twelve months ended December 31, 2012, we record pipelines and facilities assets at the lower of cost or net realizable value.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded at February 15, 2012 in connection with our acquisition of LE.

Construction in Progress. Construction in progress expenditures related to refurbishment activities at our petroleum refinery located in Nixon, Wilson County, Texas (the “Nixon Facility”) are capitalized as incurred. Depreciation begins once the asset is placed in service.

Intangibles – Goodwill and Other

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

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

8

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

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

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill for the twelve months ended December 31, 2012.  The impairment recognized for the twelve months ended December 31, 2012 represented 100% of goodwill.

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

Debt Issue Costs

We have debt issue costs related to certain of our debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations.

Debt issue costs, net of accumulated amortization, totaled $523,885 and $532,335 at March 31, 2013 and December 31, 2012, respectively.  Accumulated amortization was $152,095 and $143,645 at March 31, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Loan.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2013 and 2012.  See “Note (16) Notes Payable” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including naphtha, distillates and atmospheric gas oil. Revenue from refined product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

9

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Customer assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at March 31, 2013 was not material.

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

Income Taxes

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (22) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

10

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Future asset retirement costs include costs to dismantle, relocate or dispose of our offshore platform, pipeline systems and related onshore facilities, plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on a quarterly basis.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical volumes are not exchanged and these contracts are net settled with cash. We recognize all commodity hedge transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold using mark-to-market accounting.

Computation of Earnings Per Share

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

The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS (“EPS”) is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock and similar instruments is dependent on this average stock price and will increase as the average stock price increases.

Stock Based Compensation

In accordance with FASB ASC guidance for stock based compensation, share-based payments to employees, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in the consolidated statement of income over the service period (generally the vesting period).

11

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Treasury Stock

We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our Condensed Consolidated Balance Sheets.

Business Combinations

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

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

Reclassification

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation. The most significant of these reclassifications consisted of an increase in cost of refined products sold, and a corresponding decrease in refinery operating expenses.

Recently Adopted Accounting Guidance

In July 2012, FASB amended ASC guidance related to intangibles, goodwill and other. This amendment is intended to reduce the cost and complexity of the annual impairment test for indefinite-lived intangible assets other than goodwill by providing entities an option to perform a qualitative assessment to determine whether further impairment testing is necessary. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. We adopted this guidance in 2012.  The adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

New Pronouncements Issued but Not Yet Effective

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

(4) LE Acquisition

Effective February 15, 2012, we acquired 100% of the issued and outstanding membership interests of LE from Lazarus Energy Holdings, LLC (“LEH”). The acquisition was considered a business combination. As consideration for LE, we 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 Blue Dolphin 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, we 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 the issuance of the BDEC Shares, LEH owns approximately 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.

12

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

LE owns 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 180,000 barrels of refined product storage capacity. The Nixon Facility has the capability to produce products such as Non-Road, Locomotive, and Marine Diesel Fuel (“NRLM”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil.

The acquisition of LE was 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) was treated as the accounting parent (acquirer) and Blue Dolphin (the legal parent) was treated as the accounting subsidiary (acquiree).  Accordingly, financial statements presented herein reflect 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 effective date (February 15, 2012).  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 (2,098,390 shares) multiplied by the closing price of Blue Dolphin’s Common Stock on February 15, 2012 ($8.60). As a result, the fair value of Blue Dolphin was $18,046,154.

In connection with the acquisition of LE, we engaged an independent third-party to determine the fair value of 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 below table summarizes the purchase price allocation of the net assets acquired and measurement period adjustments as of the acquisition date (as adjusted). The estimated fair values of the assets acquired and liabilities assumed were based on information that was available as of the acquisition date. Measurement period adjustments for Blue Dolphin were completed during 2012.  Goodwill recognized in the transaction was related to the value expected to be received from the combination of LE’s refinery operations and Blue Dolphin’s pipeline and facilities and operational expertise.

	February 15, 2012 As Intially		Measurement Period			Purchase Price Allocation (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

13

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(5) LRM Acquisition

Effective October 1, 2012, we acquired 100% of the issued and outstanding membership interest of LRM, a wholly-owned subsidiary of LEH pursuant to an Assignment Agreement. The acquisition was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of LRM were transferred at their carrying amounts at the date of transfer and the results of operations are included in our financial results for the three months ended March 31, 2013. LRM did not have significant assets, liabilities or results of operations for the three months ended March 31, 2013. Assets and liabilities included in the consolidated balance sheets were $30,082 and $496,716, respectively, as of March 31, 2013. LRM markets petroleum storage and terminaling services at the Nixon Facility.

(6) Business Segment Information

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

Segment financials for the three months ended March 31, 2013 (and at March 31, 2013) were as follows:

	Three Months Ended March 31, 2013
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	109,171,507		$	73,148		$	-		$	-		$	109,244,655
Less:  Operation cost(2)		(109,063,677	)		(96,835	)		(57,664	)		(459,146	)		(109,677,321	)
Other non-interest income		278,350			-			-			-			278,350
EBITDA	$	386,180		$	(23,686	)	$	(57,664	)	$	(459,146	)
Depletion, depreciation and amortization														(328,788	)
Other income (expense), net														(280,228	)
Loss from continuing operations,
before income taxes													$	(763,331	)
Loss from discontinued operations													$	-
Capital expenditures	$	530,226		$	-		$	-		$	-		$	530,226
Identifiable assets(3)	$	50,131,322		$	1,628,612		$	33,773		$	967,906		$	52,761,612

___________________________________

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $36,440 and an unrealized gain of $188,150.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

14

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Segment financials for the three months ended March 31, 2012 (and at March 31, 2012) were as follows:

	Three Months Ended March 31, 2012
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	45,770,963		$	69,910		$	6,056		$	-		$	45,846,929
Less:  Operation cost(2)		(46,862,438	)		(195,717	)		(204,287	)		(117,639	)		(47,380,081	)
Other non-interest income		93,955			-			-			-			93,955
EBITDA	$	(997,520	)	$	(125,807	)	$	(198,231	)	$	(117,639	)
Depletion, depreciation and amortization														(255,753	)
Other income (expense), net														(231,867	)
Loss from continuing operations,
before income taxes													$	(1,926,817	)
Loss from discontinued operations													$	(12,514	)
Capital expenditures	$	1,349,332		$	-		$	-		$	-		$	1,349,332
Identifiable assets(3)	$	56,220,025		$	12,567,746		$	5,605,448		$	1,123,919		$	75,517,138

_____________________

(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.

(7) Fair Value Measurement

We are subject to gains or losses on certain financial assets based on our various agreements and understandings with Genesis. Pursuant to these agreements and understandings, Genesis can execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity risks associated with our refined petroleum products and crude oil inventory and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil inputs. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreements with Genesis, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments by Genesis. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded derivatives in our books and records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions executed on our behalf involving identical or comparable assets or liabilities.

15

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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 March 31, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our longer term debt at March 31, 2013 and December 31, 2012 was $15,743,767 and $15,806,477, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013 and the basis for that measurement:

			Fair Value Measurement at March 31, 2013 Using
Financial liabilities:	Carrying Value as at March 31, 2013		'Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		'Significant Other Observable Inputs (Level 2)		'Significant Unobservable Inputs (Level 3)
Commodity contracts	$	188,150	$	188,150	$	-	$	-

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

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

Under our refined petroleum products and crude oil inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations in our inventory. The physical volumes are not exchanged, and these contracts are net settled by Genesis with cash.

The fair value of these contracts is reflected in the consolidated balance sheets and the related net gain or loss is recorded within cost of refined petroleum products sold in the consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end.

Commodity transactions are executed by Genesis to minimize transaction costs, monitor consolidated net exposures and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products and crude oil when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a futures contract is made solely by Genesis, Genesis typically confers with management as part of their decision making process.

Due to mark-to-market accounting during the term of the commodity contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations. Additionally, Genesis may be required to collateralize any mark-to-market losses on outstanding commodity contracts.

16

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

As of March 31, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -  net short (long) positions		50,000		-		-		-

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

		Fair Value
Liabilities Derivatives	Balance Sheets Location	March 31, 2013		December 31, 2012
Commodity contracts	Accrued expenses and other current liabilities	$	188,150	$	136,100

The following table provides the effect of derivative instruments on the consolidated statements of operations for the three months ended h 31, 2013 and 2012: 

		Gain (Loss) Recognized
Derivatives	Statements of Operations Location	March 31, 2013			March 31, 2012
Commodity contracts	Cost of refined products sold	$	(188,150	)	$	-

(9) Concentration of Risk

Key Supplier. GEL TEX Marketing, LLC (“GEL”) is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2014.

Significant Customers. Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. For the three months ended March 31, 2013, our four largest customers accounted for approximately 81% of our refined petroleum products sales.

Remainder of Page Intentionally Left Blank

17

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

	March 31,			March 31,
	2013			2012
Low-sulfur diesel		51.7	%		86.3	%
Naphtha		26.2	%		7.3	%
Atmospheric gas oil		22.1	%		6.4	%
		100.0	%		100.0	%

(10) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	March 31,		December 31,
	2013		2012
Prepaid insurance	$	138,959	$	185,814
Prepaid restructuring fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		20,000		20,000
	$	208,959	$	228,314

(11) Deposits

Deposit balances consisted of the following:

	March 31,		December 31,
	2013		2012
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
Deposits	$	1,245,910	$	1,236,447

18

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(12) Inventories

Inventory balances consisted of the following:

	March 31,		December 31,
	2013		2012
Low-sulfur diesel	$	972,943	$	397,240
Naphtha		2,210,804		1,562,055
Atmospheric gas oil		587,004		322,356
Crude		19,041		19,041
	$	3,789,792	$	2,300,692

(13) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	March 31,		December 31,
	2013		2012
Refinery and facilities	$	34,384,328	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		629,424		577,567
		37,150,964		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,002,938		1,674,151
		35,148,025		35,040,826
Construction in Progress		915,497		821,259
Property, Plant and Equipment, Net	$	36,063,523	$	35,862,085

(14) Discontinued Operations

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

19

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

	March 31,		March 31,
	2013		2012
Revenue	$	-	$	194,284
Lease operating expenses		-		182,375
Depletion, depreciation and amortization		-		22,209
Accretion expense		-		2,214
Total costs and expenses		-		206,798
Loss from discontinued operations, net of tax	$	-	$	(12,514	)

(15) Accounts Payable, Related Party

LEH, which owns approximately 80% of our 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”).

Under the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and 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.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended March 31, 2013 and March 31, 2012 were $2,745,209 (approximately $2.80 per barrel) and $1,062,751 (approximately $2.72 per barrel). At March 31, 2013 and December 31, 2012, the amounts outstanding to LEH were $2,178,061 and $1,594,021, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets.

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

20

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(16) Notes Payable

Notes payable at March 31, 2013 and December 31, 2012 was $9,348,518 and $43,941, respectively. The Refinery Loan portion of notes payable at March 31, 2013 and December 31, 2012 was $9,298,183 and $0, respectively.

Refinery Loan.  In September 2008, LE obtained a loan from First International Bank (“FIB”) in the amount of $10,000,000 (the “Refinery Loan”).  The Refinery Loan accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at March 31, 2013) and has a maturity date of October 2028.  The Refinery Loan is: (i) secured by a first lien on the Nixon Facility and general assets of LE and (ii) subject to certain restrictive financial covenants related to debt to net worth and current ratio.  Currently, we are not in compliance with certain financial covenants and, since August 2011, the Refinery Loan has been subject to a forbearance agreement (the “Forbearance Agreement”). Interest was accrued on the Refinery Loan in the amount of $178,646 and $250,070 at March 31, 2013 and December 31, 2012, respectively.

The Forbearance Agreement provides for a reduced minimum monthly payment on the Refinery Loan of $60,000.  The initial forbearance period under the Forbearance Agreement commenced in August 2011 and ended in August 2012 (the “Initial Forbearance Period”) with an additional one year extension period beyond the Initial Forbearance Period ending on August 12, 2013 (the “Extended Forbearance Period” and together with the Initial Forbearance Period, the “Forbearance Period”), if we satisfied certain conditions.  In October 2011, the Refinery Loan and its related security documents (the “Refinery Loan Documents”) were acquired by American First National Bank (“AFNB”).  In June 2012, AFNB sent a letter to LE outlining what AFNB believed to be contraventions to certain provisions of the Refinery Loan, the Refinery Loan Documents and the Forbearance Agreement, including an assertion that Blue Dolphin’s acquisition of LE represented a change of control of LE, resulting in a default under the Refinery Loan.  We responded to AFNB expressing a belief that LE was in compliance with provisions of the Refinery Loan Documents.  In December 2012, AFNB sent a letter to LE confirming that LE was in compliance with the provisions of the Refinery Loan Documents, and providing for an extension of the Forbearance Agreement through the Extended Forbearance Period.

During the Forbearance Period, we remain subject to the terms, conditions and covenants of the Refinery Loan, other than those that our compliance with is expressly waived by the Forbearance Agreement.  Further, AFNB may terminate the Forbearance Agreement and any extensions thereof at any time if any of the following events (the “Termination Events”) occur:

● We do not, upon the Nixon Facility becoming operational, and the cessation of the payment of tank storage fees by Genesis to us, make the required minimum monthly payment to AFNB;

● 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 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 has a receiver or similar official appointed.

As of the date of filing of this report, no Termination Events have occurred.

After all past due principal and interest (as well as costs, fees and taxes) have been paid, AFNB will: (i) re-amortize the Refinery Loan to the original maturity date of October 1, 2028 and (ii) apply twelve consecutive additional monthly payments in the amount of $83,333.33 towards replenishing the $1,000,000 payment reserve required under the Refinery Loan in accordance with the Forbearance Agreement.

Short-Term Note for Financing Costs.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing costs was $34,866 and $39,866 at March 31, 2013 and December 31, 2012, respectively.  The unsecured note, which bears interest at 18% and was originally due in January 2012, has been extended to June 2013. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $15,469 and $0 at March 31, 2013 and December 31, 2012, respectively.  In January 2013 we acquired a pressure washer under an interest-free, short-term capital lease.  We also reclassified capital leases from long-term debt at December 31, 2012 to short-term debt at March 31, 2013 as they mature at various dates through February 2014.  These capital leases have interest rates ranging from 0% to 13.04%.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

The balance on a short-term note related to previously owned trucks for use at the Nixon Facility was $0 and $4,075 at March 31, 2013 and December 31, 2012, respectively.  The unsecured note bore interest at 5%.

21

 (17) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	March 31,		December 31,
	2013		2012
Excise taxes	$	254,549	$	292,303
Salaries		109,717		134,501
Turnaround expenses		141,406		-
Transportation		-		69,551
Other payable		37,605		-
Property taxes		13,500		-
Insurance		57,492		-
Unrealized hedging loss		188,150		136,100
Unearned revenue		92,783		92,783
	$	895,202	$	725,238

(18) Asset Retirement Obligations

Refinery and Facilities

Management has concluded that there is no legal or contractual obligation to dismantle or remove our refinery and facilities assets. Management believes that our refinery and facilities assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Oil and Gas Properties and Pipelines and Facilities Assets

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

Asset retirment obligations as of December 31, 2012	$	921,260
Accretion expense		25,164
		946,424
Less:  current portion of asset retirement obligations		90,601
Asset retirement obligations, long-term balance
at March 31, 2013	$	855,823

Actual plugging and abandonment expenses associated with HI-A7 have exceeded the estimated ARO liability. Additional plugging and abandonment expenses associated with HI-A7 will be recognized as a loss in the period incurred. For the three months ended March 31, 2013, we recognized $27,451 in abandonment expense for AROs associated with HI-A7. We will record additional plugging and abandonment costs for HI-A7 as information becomes available from the operator, Apache Corp., to substantiate actual and/or probable costs.

(19) Long-Term Debt

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

	March 31,		December 31,
	2013		2012
Refinery Loan	$	-	$	9,298,183
Notre Dame Debt		1,300,000		1,300,000
Construction Funding		5,145,584		5,206,175
Captial Leases		-		2,119
		6,445,584		15,806,477
Less: Current portion of long-term debt		1,485,000		1,816,960
	$	4,960,584	$	13,989,517

22

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Notre Dame Debt.  LE obtained a loan in the original amount of $8,000,000 from Notre Dame Investors, Inc., which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at the default rate of 16% and is secured by a subordinated lien on the Nixon Facility and general assets of LE.  Interest was accrued on the note in the amount of $910,071 and $858,784 at March 31, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with the Notre Dame Debt.

In August 2011, LE, Milam and John Kissick, entered into an intercreditor and subordination agreement under which Mr. Kissick, as a subordinated lien holder on the Nixon Facility, agreed to (i) subordinate his lien to the liens of Milam under the Construction and Funding Agreement and (ii) forebear his rights under the note evidencing the Notre Dame Debt for so long as amounts are outstanding on the Refinery Loan and any senior construction funding obligations.  Furthermore, 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 evidencing the Notre Dame Debt under applicable law or otherwise so long as the Joint Marketing Agreement, which expires in August 2014, is in effect and has not been terminated.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  Interest was accrued on the Construction and Funding Agreement in the amount of $457,568 and $386,695 at March 31, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with this obligation.

See “Note (23) Commitments and Contingencies” of this report for additional disclosures related to amendments to the Joint Marketing Agreement, which previously added to our obligation amount under the Construction and Funding Agreement.

Capital Leases.  LE was obligated under various capital lease agreements for equipment totaling $2,119 at December 31, 2012.  As the capital leases mature at various dates through February 2014, capital lease obligations totaling $1,835 were reclassified to short-term notes payable at March 31, 2013.

23

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(20) Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month.  The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. Rent expense for the office lease was $29,041 and $28,344 for the three months ended March 31, 2013 and 2012, respectively.

(21) Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia.  The non-cash transaction was completed on February 28, 2013.  Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of Common Stock, which represented a recovery of a significant portion of the 342,857 shares of Common Stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  We expect to use the treasury stock to issue restricted Common Stock to our independent directors as compensation for services rendered and for stock option exercises.  As of March 31, 2013, there were 150,000 shares of treasury stock.

(22) Income Taxes

LE is a limited liability company and, prior to our acquisition of LE, its taxable income or loss flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon LE's acquisition, LE became the 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 LE acquisition, Section 382 of the Internal Revenue Code imposes a limitation on the use Blue Dolphin’s NOLs.  The amount of NOLs subject to such limitations is approximately $18.5 million. The NOL generated subsequent to the LE acquisition, approximately $6.4 million, is not subject to any such limitation. For the three months ended March 31, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

Income tax expense was $0 and $30,563 for the three months ended March 31, 2013 and 2012, respectively. Income tax expense related to state income tax.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax. At March 31, 2013, we accrued $0 in TMT.

(23) Commitments and Contingencies

Management Agreement

See “Note (15) Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Genesis Agreements

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

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. 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, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement 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;

● Joint Marketing Agreement -- The Joint Marketing Agreement sets forth the terms of the agreement between LE and GEL pursuant to which the parties will market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil pursuant to the Crude Supply Agreement) as follows:

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

(b) Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any Accounting Fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

(d) Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.

(e) After the Threshold Date, if GEL sustains losses, it can recoup those losses by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated.

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. 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 was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

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

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

26

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(c) In February 2013, Milam paid a vendor $64,357.50 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees.  In addition, Milam and GEL incurred legal fees and expenses related to settling the matter.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

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

As of March 31, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,145,584. As of March 31, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $851,296.

As of March 31, 2013, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the three months ended March 31, 2013, no payments were made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits.

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

In June 2012, we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LTRI, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.

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

Lazarus Energy Development, LLC (“LED”) Option

In February 2012 we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option.

27

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Legal Matters

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

Environmental Matters

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

(24) Earnings Per Share

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

	Three Months Ended March 31,
	2013			2012
Loss from continuing operations, net of tax	$	(763,331	)	$	(1,957,380	)
Loss from discontinued operations, net of tax		-			(12,514	)
Net loss		(763,331	)		(1,969,894	)
Basic and diluted loss per common share
Continuing operations	$	(0.07	)	$	(0.21	)
Discontinued operations	$	-		$	-
Basic and diluted loss per common share	$	(0.07	)	$	(0.21	)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,510,334			9,476,748

Diluted EPS is computed by dividing net loss available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2013 and 2012 excludes stock options outstanding as they would be anti-dilutive.

For the three months ended March 31, 2012, the weighted average number of shares of common stock outstanding was computed as LE’s number of shares of common stock outstanding from January 1, 2012 to February 15, 2012 (the beginning of the period to the date of LE’s acquisition by Blue Dolphin) combined with Blue Dolphin’s number of shares of common stock outstanding from February 15, 2012 to March 31, 2012 (the date of LE’s acquisition by Blue Dolphin to the end of the period).  For the period prior to the date of LE’s acquisition by Blue Dolphin, LE’s number of shares of common stock was computed as LE’s one member unit prior to the acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(25) Stock Options

Our 2000 Stock Incentive 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 Compensation Committee of the Board of Directors (the “Board”) approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

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

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the three months ended March 31, 2013.

At March 31, 2013, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at March 31, 2013		14,642	$	19.67		0.6	$	-
Options exercisable at March 31, 2013		14,642	$	19.67		0.6	$	-

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Notes to Consolidated Financial Statements

(Continued)

We recognized no compensation expense for vested stock options for the three months ended March 31, 2013 and 2012. As of March 31, 2013, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the three months ended March 31, 2013, we recognized $50,000 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

Remainder of Page Intentionally Left Blank

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Blue Dolphin Energy Company & Subsidiaries

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

The following discussion of our financial condition and results of operations should be read in conjunction with the risk factors, unaudited consolidated financial statements and notes included hereto, as well as the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”). In this document, the words “Blue Dolphin,” “we,” “us” and “our” refer to Blue Dolphin Energy Company and its subsidiaries.

Forward Looking Statements

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Quarterly Report on Form 10-Q, and in particular under the sections entitled “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 1. Legal Proceedings” relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

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

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

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

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

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

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

● our dependence on Lazarus Energy Holdings, LLC ("LEH") for management of the Nixon Facility and our other operations;

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

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

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

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

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

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

● operating hazards such as fires and explosions;

● insurance coverage limitations;

● environmental costs and liabilities associated with our operations;

● retention of key personnel;

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

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

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

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Blue Dolphin Energy Company & Subsidiaries

● competition from larger companies;

● acquisition expenses and integration difficulties; and

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

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

Company Overview

Blue Dolphin Energy Company (www.blue-dolphin-energy.com), a Delaware corporation (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) was formed in 1986 as a holding company. We conduct substantially all of our operations through our wholly-owned subsidiaries.  We are primarily an independent refiner and marketer of petroleum products.  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refinery Operations

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

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

Pipeline Transportation

Our pipeline operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines in the U.S. Gulf of Mexico. Producers and shippers are charged a fee based on anticipated throughput volumes.  For the three months ended March 31, 2013, our pipeline transportation business segment had no revenue.

Oil and Gas Exploration and Production

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the three months ended March 31, 2013 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company (‘BDEX”), a wholly owned subsidiary, completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.  For the three months ended March 31, 2013, our oil and gas exploration and production business segment had no revenue.

Other Assets

We own a non-hazardous Class I salt water disposal well located near the town of Mermentau, Jefferson Davis Parish, Louisiana. The well is currently inactive.

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Key Operating Statistics

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

	Three Months Ended March 31,
	2013			2012
Nixon Facility
Operating days		85			60
Total refinery throughput(1)
bbls		978,805			391,509
bpd		11,515			6,525
Capacity utilization rate		77	%		44	%
Total refinery production
bbls		958,306			384,152
bpd		11,274			6,403
Capacity utilization rate		75	%		43	%

_______________

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

Major Influences on Results of Operations

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

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

The Nixon Facility has the capability to process substantial volumes of low-sulfur crude oils (sweet crude) to produce a high percentage of light, high-value refined petroleum products. Sweet crude derived from the surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s crude oil input.

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

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

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Critical Accounting Policies and Estimates

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

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

Relationship with Genesis

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

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

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

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

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

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. 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, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement 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;

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● Joint Marketing Agreement -- The Joint Marketing Agreement sets forth the terms of the agreement between LE and GEL pursuant to which the parties will market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil pursuant to the Crude Supply Agreement) as follows:

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

(b) Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.

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

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(d) Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.

(e) After the Threshold Date, if GEL sustains losses, it can recoup those losses by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated.

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. 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 was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

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

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

(c) In February 2013, Milam paid a vendor $64,357.50 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees. In addition, Milam and GEL incurred legal fees and expenses related to settling the matter. In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

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

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Blue Dolphin Energy Company & Subsidiaries

As of March 31, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,145,584. As of March 31, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $851,296.

As of March 31, 2013, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the three months ended March 31, 2013, no payments were made to American First National Bank (“AFNB”) under the Refinery Loan in respect of LE’s ratable share of Gross Profits. Subsequent to the Current Quarter, we paid AFNB $178,646 in arrearages.

Results of Operations

Three Months Ended March 31, 2013 (the “Current Quarter”) Compared to Three Months Ended March 31, 2012 (the “Prior Quarter”)

During the Prior Quarter, the Nixon Facility, which was refurbished and began operations in February 2012, operated for a total of 60 days at 44% of operating capacity. During the Current Quarter, the Nixon Facility operated for 85days at 77% of operating capacity. During the Current Quarter, the Nixon Facility underwent a planned 7 day annual maintenance turnaround in which the processing units were shut-down.

Current Quarter Compared to Prior Quarter

Summary. For the Current Quarter we reported a loss from continuing operations, net of tax, of $763,311, or a loss of $0.07 per share, compared to a loss from continuing operations, net of tax, of $1,957,380, or a loss of $0.21 per share, for the Prior Quarter. We reported a loss from discontinued operations of $12,514 in the Prior Quarter compared to no loss from discontinued operations in the Current Quarter. The loss from continuing operations, net of tax, in the Current Quarter was primarily attributable to the planned maintenance turnaround and lower refining margins. We continue to take steps to more effectively operate the refinery and manage the spread between our cost to acquire crude oil and the price of the refined petroleum products that we ultimately sell. During the Current Quarter, we adopted a condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, such as installation of new laboratory equipment and a new caustic system, to enhance profitability of our existing assets.

Total Revenue from Operations. For the Current Quarter we had total revenue from operations of $109,244,655 compared to total revenue from operations of $45,846,929 for the Prior Quarter. Substantially all of our revenue in the Current Quarter came from refined product sales, which generated revenue of $109,171,507, or 99% of total revenue from operations, compared to $45,770,963, or 99% of total revenue from operations, in the Prior Quarter.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $106,322,661 for the Current Quarter compared to $45,641,226 for the Prior Quarter.

Refinery Operating Expenses. We recorded refinery operating expenses of $2,745,209 in the Current Quarter, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH. For the Prior Quarter, we recorded refinery operating expenses of $1,062,751. See “Part I, Item 1. Financial Statements - Note (15), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $45,371 in the Current Quarter compared to $109,618 in the Prior Quarter.

Lease Operating Expenses. Lease operating expenses totaled $26,901 in the Current Quarter compared to $19,338 in the Prior Quarter.

General and Administrative Expenses. General and administrative expenses decreased from $525,587 in the Prior Quarter to $484,564 in the quarter. The expenses in the Current Quarter were primarily related to leased corporate personnel costs, as well as consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization increased from $255,753 in the Prior Quarter to $328,788 in the Current Quarter.

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Abandonment Expense. We recognized $27,451 of abandonment expense in the Current Quarter related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount, which exceeded the asset retirement obligation liability, was recognized as a loss during the period. There was no comparable expense in the Prior Quarter.

Other Income. We recognized $278,350 in net tank rental revenue in the Current Quarter compared to $93,955 in the Prior Quarter.

Discontinued Operations, Net of Tax. We reported a loss from discontinued operations, net of tax, of $12,514 in the Prior Quarter compared to $0 in the Current Quarter.

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

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

Following is a reconciliation of EBITDA by business segment for the three months ended March 31, 2013 (and at March 31, 2013) and the three months ended March 31, 2012 (and at March 31, 2012):

	Three Months Ended March 31, 2013
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	109,171,507		$	73,148		$	-		$	-		$	109,244,655
Less:  Operation cost(2)		(109,063,677	)		(96,835	)		(57,664	)		(459,146	)		(109,677,321	)
Other non-interest income		278,350			-			-			-			278,350
EBITDA	$	386,180		$	(23,686	)	$	(57,664	)	$	(459,146	)	$	(154,316	)
Depletion, depreciation and amortization														(328,788	)
Other income (expense), net														(280,228	)
Loss from continuing operations,
before income taxes													$	(763,331	)
Loss from discontinued operations													$	-
Capital expenditures	$	530,226		$	-		$	-		$	-		$	530,226
Identifiable assets(3)	$	50,131,322		$	1,628,612		$	33,773		$	967,906		$	52,761,612

_______________

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations. Cost of refined products sold includes a realized loss of $36,440 and an unrealized gain of $52,050.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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	Three Months Ended March 31, 2012
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	45,770,963		$	69,910		$	6,056		$	-		$	45,846,929
Less:  Operation cost(2)		(46,862,438	)		(195,717	)		(204,287	)		(117,639	)		(47,380,081	)
Other non-interest income		93,955			-			-			-			93,955
EBITDA	$	(997,520	)	$	(125,807	)	$	(198,231	)	$	(117,639	)	$	(1,439,197	)
Depletion, depreciation and amortization														(255,753	)
Other income (expense), net														(231,867	)
Loss from continuing operations,
before income taxes													$	(1,926,817	)
Loss from discontinued operations													$	(12,514	)
Capital expenditures	$	1,349,332		$	-		$	-		$	-		$	1,349,332
Identifiable assets(3)	$	56,220,025		$	12,567,746		$	5,605,448		$	1,123,919		$	75,517,138

___________________

(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.

Liquidity and Capital Resources

Sources and Uses of Cash. At March 31, 2013, our available cash was $88,059. Pursuant to the Joint Marketing Agreement, 10% of gross profits was directly remitted by GEL to AFNB on LE’s behalf to repay all past due principal and interest. Subsequent to the Current Quarter, GEL paid AFNB in the amount of $178,646 to repay all arrearages. As a result, LE’s share of gross profits will increase to 20% with no required profit share payments to AFNB.

We are currently relying on our profit share, GEL and LEH for our capital requirements. GEL and LEH may, but are not required, to fund our capital requirements. During the Current Quarter, the Deficit Amount financed by GEL was $851,296 and the capital amount funded by LEH was $584,040. For months in which GEL finances Deficit Amounts, LE does not receive any of its profit share until the Deficit Amounts have been repaid. There can be no assurances that GEL and/or LEH will continue to fund our capital requirements. In the event capital requirements are not funded by our profit share, GEL or LEH, we may experience a significant and material adverse effect on our operations, liquidity and financial condition. See “Item 1A. Risk Factors” in our Annual Report for risk factors related to our capital needs.

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Blue Dolphin Energy Company & Subsidiaries

	For Three Months Ended March 31,
	2013			2012
Cash flow from operations
Adjusted loss from continuing operations	$	(261,965	)	$	(1,651,727	)
Adjusted loss from discontinued operations		-			11,909
Change in assets and current liabilities		515,670			61,459
Total cash flow from operations		253,705			(1,578,359	)
Cash inflows (outflows)
Proceeds from issuance of debt		15,031			2,364,012
Payments on long term debt		(60,876	)		(2,916	)
Cash acquired on Acquisition		-			1,674,594
Capital expenditures		(530,226	)		(1,349,332	)
Payments on note payble		(10,472	)		-
Total cash inflows (outflows)		(586,542	)		2,686,358
Total change in cash flows	$	(332,837	)	$	1,107,999

Our sources of liquidity are advances for funding under the Construction and Funding Agreement, revenue we receive under the Joint Marketing Agreement, tank rental income and cash on hand. We purchase our crude oil for the Nixon Facility through an exclusive supply agreement with GEL. Under this agreement, the purchases of the crude oil are completed by GEL. We believe that the aforementioned liquidity sources will be sufficient to satisfy anticipated cash requirements associated with our business during the next 12 to 18 months. Our ability to generate cash to fund our operations depends on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors beyond our control.

For the Current Quarter, we experienced positive cash flow from operations of $253,705. For the Prior Quarter, we experienced negative cash flow from operations of $1,578,359. This represents an improvement in cash flow from operations of $1,832,064 for the Current Quarter compared to the Prior Quarter.

We have implemented an operational strategy that we believe will improve liquidity over time, as follows:

(a) Maintain Efficient Refinery Operations and Promote Operational Excellence and Reliability – In the Current Quarter we adopted a predictive maintenance turnaround policy to operate the refinery as reliably and efficiently as possible. Under this condition-based approach to maintenance, we assess whether equipment will fail during some future period and then take action to avoid the consequences of such a failure. Compared to a preventive maintenance approach where equipment is taken off-line, opened up and inspected on a predetermined, periodic basis, we believe the predictive maintenance approach will enable us to better control costs and manage production schedules more efficiently. During the Current Quarter, the Nixon Facility successfully completed a 7 day maintenance turnaround in which the facility was taken offline. GEL agreed to pay the actual costs associated with the maintenance turnaround. Such costs are being added to the obligation amount we owe under the Construction and Funding Agreement. For the three months ended March 31, 2013, the Nixon Facility had a utilization rate of 77%; and

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(b) Enhance Profitability of our Existing Assets and Invest in Organic Growth – In the Current Quarter we completed several capital improvement projects at the Nixon Facility, including installation of: (i) new laboratory equipment, improving both the speed and spectrum of product samples, (ii) a new caustic system, aiding in the reduction of sulfur content of certain refined products and (iii) a new salt tower, increasing the drying effectiveness of the distillation tower. We also initiated a project to automate the metering system and refurbish the flare system at the Nixon Facility. GEL agreed to fund these capital expenditures under the Construction and Funding Agreement. Such costs are being added to the obligation amount we owe under the Construction and Funding Agreement.

We continue to work with our vendors to bring our outstanding accounts payable current as expeditiously as possible. In the event that our efforts are not successful, we will experience a significant and material adverse effect on our continuing operations, liquidity and financial condition. In the Current Quarter, Milam settled amounts owed by LE to a vendor for services rendered at the Nixon Facility. Such amounts were added to the obligation amount we owe under the Construction and Funding Agreement.

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the three months ended March 31, 2013 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company (‘BDEX”), a wholly owned subsidiary, completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.

We recognized $27,451 of abandonment expense in the Current Quarter related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount, which exceeded the asset retirement obligation liability, was recognized as a loss during the period. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

Capital expenditures in the Current Quarter totaled $530,226, all of which related to refurbishment of the Nixon Facility. We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $5,145,584 and $5,206,175, including Deficit Amounts, at March 31, 2013 and December 31, 2012, respectively.

The principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183 at March 31, 2013 and December 31, 2012. As of the date of the filing of this report, the Refinery Loan is subject to a forbearance agreement (the "Forbearance Agreement").

As of March 31, 2013, past due principal and interest (as well as costs, fees and taxes) on the Refinery Loan was $178,646. After all past due principal and interest has been paid AFNB has agreed to: (i) re-amortize the Refinery Loan to the original maturity date of October 1, 2028 and (ii) apply twelve consecutive additional monthly payments in the amount of $83,333.33 towards replenishing the $1.0 million payment reserve required under the Refinery Loan in accordance with the Forbearance Agreement.

The principal balance outstanding on the Notre Dame Debt note, which is currently in default, was $1,300,000 at March 31, 2013 and December 31, 2012. There are no financial covenants associated with this debt.

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (16) Notes Payable and Note (19) Long-Term Debt” of this report for additional disclosures related to our debt obligations.

41

Blue Dolphin Energy Company & Subsidiaries

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Interest Rate Risk. We are exposed to interest rate volatility with regard to existing variable rate debt tied to movements in the U.S. prime rate. At March 31, 2103, we had $9,298,183 of variable interest debt with a weighted average interest rate at year end of approximately 5.50%.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Based on that evaluation, our management, including our Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer), concluded that our disclosure controls and procedures as defined in Exchange Act Rules 13a-15(e) and 15d-15(e) were ineffective as of March 31, 2013 to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the  Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

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

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act  during the three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

42

Blue Dolphin Energy Company & Subsidiaries

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this Form 10-Q, you should carefully consider the factors discussed under Item 1A, “Risk Factors” and elsewhere in our Annual Report. These risks and uncertainties could materially and adversely affect our business, financial condition and results of operations. Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business. Except for the addition below, there have been no material changes in our assessment of our risk factors from those set forth in our Annual Report.

We may incur significant liability under, or costs and capital expenditures to comply with, environmental regulations relating to the recommissioning of the Nixon Facility

The Nixon Facility returned to service in February 2012. We are currently undergoing a comprehensive review to determine our compliance with relevant federal, state and local environmental laws. During the course of our review, we may discover that we are not in compliance with existing environmental regulations. To the extent that we are out of compliance, we may incur significant liabilities, costs and capital expenditures to comply with such environmental regulations, which are complex and change frequently. Costs of compliance are often unpredictable, and there can be no assurance that the future costs will not be material. It is possible that we may identify additional cost in the future, which could result in additional obligations and expenses, including fines and penalties.

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

None.

ITEM 3 DEFAULTS UPON SENIOR SECURITIES

See “Note (16) Notes Payable and Note (19), Long-Term Debt” in Part I. Financial Information, Item 1. Financial Statements – Notes to Condensed Consolidated Financial Statements (Unaudited) of this report for disclosures related to defaults on debt.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

43

Blue Dolphin Energy Company & Subsidiaries

ITEM 6.EXHIBITS

(a)	Exhibits:
	The following exhibits are filed herewith:
	10.1	Letter Agreement between Lazarus Energy, LLC, GEL TEX Marketing, LLC and Milam Services, Inc. dated February 21, 2013.
	10.2	Letter Agreement between Lazarus Energy, LLC, GEL TEX Marketing, LLC and Milam Services, Inc. dated February 21, 2013.
	31.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
	32.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
	101.INS	XBRL Instance Document.
	101.SCH	XBRL Taxonomy Schema Document.
	101.CA	XBRL Calculation Linkbase Document.
	101.LAB	XBRL Label Linkbase Document.
	101.PRE	XBRL Presentation Linkbase Document.
	101.DEF	XBRL Definition Linkbase Document.

44

SIGNATURES

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

		By: BLUE DOLPHIN ENERGY COMPANY
Date: May 15, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)
Date: May 15, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

45

EX-10.1

Exhibit 10.1

genesisenergy

February 21, 2013

Lazarus Energy LLC

801 Travis, Suite 2100

Houston, Texas 77002

Attention: Jonathan Carroll

GEL TEX Marketing, LLC

Milam Services, Inc.

919 Milam, Suite 2100

Houston, Texas 77002

Attention: Steve Nathanson

Re: Letter Agreement Regarding Distribution to Recover Payment made to Settle Claims

Gentlemen:

Reference is made to that certain (i) Joint Marketing Agreement dated August 12, 2011 (as amended, restated or supplemented from time to time, the "JMA"), by and between Lazarus Energy LLC, a Delaware limited liability company ("Lazarus"), and GEL Tex Marketing, LLC, a Delaware limited liability company ("GEL"), (ii) Construction and Funding Contract dated August 12, 2011 (as amended, restated or supplemented from time to time, the "CFC"), by and between Lazarus and Milam Services, Inc., a Delaware corporation ("MSI"), (iii) Crude Oil Supply and Throughput Services Agreement dated August 12, 2011 by and between GEL and Lazarus, (iv) Letter Agreement dated June 25, 2012 by and between GEL, MS1 and Lazarus regarding expense payments and reservations of rights ("Operating Expense Payment Letter Agreements"), (v) Acknowledgment Letter dated June 1, 2012 addressed to Lazarus by GEL (the "Acknowledgment Letter"), (vi) Letter Agreement dated December 20, 2012 by and between GEL, MSI and Lazarus regarding recovery of December 2012 Payments ("December 2012 Payments Letter Agreement"), and (vii) Letter Agreement Regarding Advances to Fund February 2013 Turnaround dated February 21, 2013 ("Turnaround Letter"). Capitalized terms not otherwise defined herein shall have the meanings set forth in the CFC.

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

Section 1. Acknowledgements

MSI and Anchor Industrial Services, LLC ("Anchor") have entered into a Confidential Partial Settlement Agreement and Release ("Settlement") in Cause No. 2012-53656; Anchor Industrial Services, LLC v. Lazarus Texas Refinery I, LLC, Lazarus Energy LLC, and Milam Services, Inc.; In the 151st Judicial District Court of Harris County, Texas (the "Litigation"). Under the terms of the Settlement, MSI will pay to Anchor the sum of $64,357.50 (sixty four thousand three hundred fifty seven dollars and 50/100 dollars) for a release and dismissal of all Anchor claims against MSI related to the certain services ordered by Lazarus and provided by Anchor attributable to the Nixon facility (the "Settlement Payment"). This payment includes the Anchor invoiced amount of $62,562.42 and legal fees incurred by Anchor in the amount of $1,795.07. In addition, MSI and or GEL have incurred legal fees and expenses to DLA

February 12, 2013 Page 2

Piper LLP (US) ("DLA") and to Hicks Thomas LLP ("Hicks Thomas") in connection with the Litigation and Settlement and may incur additional legal fees and expenses in connection therewith as the Litigation between Lazarus and Anchor continues. As of December 31, 2012, the amount of such fees and expenses are approximately $14,500 for Hicks Thomas and $350 for DLA (the amount of such legal fees and expenses plus any legal fees and expenses incurred by GEL and/or its affiliates after the date hereof in connection with the Litigation or Settlement herein referred to as the "Legal Expenses").

1

February 12, 2013

Page 2

Section 2. Modifications to Distributions and Payments Provisions of JMA.

From and after January 1, 2013, Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the JMA until GEL has received aggregate distributions as provided in the December 2012 Payments Letter Agreement plus the amounts of the Settlement Payment and Legal Expenses. Such distributions shall not reduce the distributions of Gross Profit that GEL or its Affiliates are otherwise entitled to under the JMA.

Section 3. Certain Representations

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

(b)Lazarus hereby represents and warrants to GEL that no Forbearance Termination Event, as defined in the Forbearance Agreement has occurred, and no facts or circumstance exist that would cause a Forbearance Termination Event to occur under the Forbearance Agreement.

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

[Signature page follows.]

2

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

GEL TEX MARKETING, LLC, A Delaware limited liability company
By:	/s/ STEVE NATHANSON
Name:	Steve Nathanson
Title:	President and COO
MILAM SERVICES, INC., A Delaware corporation
By:	/s/ STEVE NATHANSON
Name:	Steve Nathanson
Title:	President and COO
LAZARUS ENERGY LLC, a Delaware limited liability company
By:	/s/ JONATHAN P. CARROLL
Name:	Jonathan P. Carroll
Title:	President

(Signature page to February 21, 2013 Settlement Letter Agreement)

3

EX-10.2

Exhibit 10.2

genesisenergy

February 21, 2013

Lazarus Energy LLC

801 Travis, Suite 2100

Houston, Texas 77002

Attention: Jonathan Carroll

GEL TEX Marketing, LLC

Milam Services, Inc.

919 Milam, Suite 2100

Houston, Texas 77002

Attention: Steve Nathanson

Re: Letter Agreement Regarding Advances to Fund February 2013 Turnaround

Gentlemen:

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

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

Section 1. Acknowledgements

The parties agree that after the date of execution of this Letter Agreement, GEL will advance to Lazarus funds necessary to pay for the actual costs associated with the scheduled refinery turnaround and capital expenditures relating to an electronic product meter, lab equipment, and certain piping in an amount equal to the actual costs of the refinery turnaround and capital expenditures, not to exceed $840,000 in the aggregate (the "Estimated Amount"). Lazarus shall provide GEL with copies of invoices and any other supporting information requested by GEL that evidences the actual costs of the Estimated Amount prior to any payment of such Estimated Amount being required from GEL.

Genesis Energy, L.P. ● 919 Milam, Suite 2100 ● Houston, Texas 77002 ●Tel: (713) 860-2500 ● Fax: (713) 860-2640

1

February 12, 2013

Page 2

All amounts advanced by GEL or its Affiliates to Lazarus pursuant to this Letter Agreement shall constitute Obligations.

Section 2. Certain Representations

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

(b)Lazarus hereby represents and warrants to GEL that no Forbearance Termination Event, as defined in the Forbearance Agreement has occurred, and no facts or circumstance exist that would cause a Forbearance Termination Event to occur under the Forbearance Agreement.

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

[Signature page follows.]

2

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

GEL TEX MARKETING, LLC, A Delaware limited liability company
By:	/s/ STEVE NATHANSON
Name:	Steve Nathanson
Title:	President and COO
MILAM SERVICES, INC., A Delaware corporation
By:	/s/ STEVE NATHANSON
Name:	Steve Nathanson
Title:	President and COO
LAZARUS ENERGY LLC, a Delaware limited liability company
By:	/s/ JONATHAN P. CARROLL
Name:	Jonathan P. Carroll
Title:	President

(Signature page to February 21, 2013 Turnaround Letter Agreement)

3

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 15, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 15, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 15, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Interim Chief Financial Officer, Treasurer and Assistant Secretary (PrincipalFinancial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 15, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

11. Deposits (Tables)

3 Months Ended

Mar. 31, 2013

Deposits Tables

Deposit balances

Deposit balances consisted of the following:

	March 31,		December 31,
	2013		2012
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
Deposits	$	1,245,910	$	1,236,447

XML

7. Fair Value Measurement (Details Narrative) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Fair Value Measurement Details Narrative
Fair value of longer term debt	$ 15,743,767	$ 15,806,477

XML

3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Accounting Policies [Abstract]
Restricted cash	$ 27,348		$ 89,593
Perecentage of revenue from major customers	81.00%
Three major customers Accounts Recievable	7,500,000
Accumulated amortization	152,095		143,645
Uninsured balances	0		170,896
Amortization expense	8,450	8,450
Debt issuance costs	523,885		532,335
Non-cash impairment charge			$ 1,445,720
Impairment charge representation in goodwill			100.00%

XML

19. Long-Term Debt (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery Loan		$ 9,298,183
Notre Dame Debt	1,300,000	1,300,000
Construction and Funding Agreement	5,145,584	5,206,175
Captial Leases		2,119
Total	6,445,584	15,806,477
Less: Current portion of long-term debt	1,485,000	1,816,960
Long term debt	$ 4,960,584	$ 13,989,517

XML

8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Mar. 31, 2013
Refined products - net short (long) positions
Volume in Thousands of barrels
Notional Contract Volumes 2013	50,000
Notional Contract Volumes 2014
Notional Contract Volumes 2015
Notional Contract Volumes 2016

XML

25. Stock Options (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Issuance of restricted common stock expense	$ 50,000

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24. Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Earnings per share

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

	Three Months Ended March 31,
	2013			2012
Loss from continuing operations, net of tax	$	(763,331	)	$	(1,957,380	)
Loss from discontinued operations, net of tax		-			(12,514	)
Net loss		(763,331	)		(1,969,894	)
Basic and diluted loss per common share
Continuing operations	$	(0.07	)	$	(0.37	)
Discontinued operations	$	-		$	-
Basic and diluted loss per common share	$	(0.07	)	$	(0.37	)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,510,334			5,261,328

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4. LE Acquisition (Tables)

3 Months Ended

Mar. 31, 2013

Business Combinations [Abstract]

Provisional price allocation for net assets acquired

	February 15, 2012 As Intially		Measurement Period			Purchase Price Allocation (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

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21. Treasury Stock (Details Narrative)	Mar. 31, 2013
Treasury Stock Details Narrative
Treasury stock	150,000

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 2) (Commodity Contracts, USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Commodity Contracts
Cost of refined products sold	$ (188,150)

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24. Earnings per share (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share [Abstract]
Income (loss) from continuing operations, net of tax	$ (763,331)	$ (1,957,380)
Loss from discontinued operations, net of tax		(12,514)
Net income (loss)	$ (763,331)	$ (1,969,894)
Basic and diluted earnings (loss) per common share
Continuing operations	$ (0.07)	$ (0.21)
Discontinued operations
Basic and diluted earnings (loss) per common share	$ (0.07)	$ (0.21)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,510,334	9,476,748

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25. Stock Options (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Shares
Options outstanding at December 31, 2012	14,642
Options granted
Options exercised
Options expired or cancelled
Options outstanding at March 31, 2013	14,642
Options exercisable at March 31, 2013	14,642	14,642
Weighted Average Exercise Price
Options outstanding at December 31, 2012
Options granted
Options exercised
Options expired or cancelled
Options outstanding at March 31, 2013	$ 19.67
Options exercisable at March 31, 2013	$ 19.67
Weighted Average Remaining Contractual Life
Options outstanding at March 31, 2013	21 days
Options exercisable at March 31, 2013	21 days
Aggregate Intrinisic Value
Options outstanding at March 31, 2013
Options exercisable at March 31, 2013

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19. Long-Term Debt (Details Narrative) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery loan accrued interest	$ 178,646	$ 250,070
Notre Dame debt accrued interest	910,071	858,784
Construction funding accrued interest	457,568	386,695
Capital leases	$ 1,835	$ 2,119
Effective rate	5.50%

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19. Long-Term Debt

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Long-Term Debt

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

	March 31,		December 31,
	2013		2012
Refinery Loan	$	-	$	9,298,183
Notre Dame Debt		1,300,000		1,300,000
Construction Funding		5,145,584		5,206,175
Captial Leases		-		2,119
		6,445,584		15,806,477
Less: Current portion of long-term debt		1,485,000		1,816,960
	$	4,960,584	$	13,989,517

Notre Dame Debt.  LE obtained a loan in the original amount of $8,000,000 from Notre Dame Investors, Inc., which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at the default rate of 16% and is secured by a subordinated lien on the Nixon Facility and general assets of LE.  Interest was accrued on the note in the amount of $910,071 and $858,784 at March 31, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with the Notre Dame Debt.

In August 2011, LE, Milam and John Kissick, entered into an intercreditor and subordination agreement under which Mr. Kissick, as a subordinated lien holder on the Nixon Facility, agreed to (i) subordinate his lien to the liens of Milam under the Construction and Funding Agreement and (ii) forebear his rights under the note evidencing the Notre Dame Debt for so long as amounts are outstanding on the Refinery Loan and any senior construction funding obligations.  Furthermore, 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 evidencing the Notre Dame Debt under applicable law or otherwise so long as the Joint Marketing Agreement, which expires in August 2014, is in effect and has not been terminated.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  Interest was accrued on the Construction and Funding Agreement in the amount of $457,568 and $386,695 at March 31, 2013 and December 31, 2012, respectively.  There are no financial covenants associated with this obligation.

See “Note (23) Commitments and Contingencies” of this report for additional disclosures related to amendments to the Joint Marketing Agreement, which previously added to our obligation amount under the Construction and Funding Agreement.

Capital Leases.  LE was obligated under various capital lease agreements for equipment totaling $2,119 at December 31, 2012.  As the capital leases mature at various dates through February 2014, capital lease obligations totaling $1,835 were reclassified to short-term notes payable at March 31, 2013.

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5. LRM Acquisition (Details Narrative) (USD $)	Mar. 31, 2013
Business Combinations [Abstract]
Assets	$ 30,082
Liabilities	$ 496,716

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14. Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2013

Discontinued Operations Tables

Operating results of discontinued operations

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

	March 31,		March 31,
	2013		2012
Revenue	$	-	$	194,284
Lease operating expenses		-		182,375
Depletion, depreciation and amortization		-		22,209
Accretion expense		-		2,214
Total costs and expenses		-		206,798
Loss from discontinued operations, net of tax	$	-	$	(12,514	)

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23. Commitments and Contingencies (Details Narrative) (USD $)	Mar. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Advances and Deficit Amounts	$ 5,145,584
Deficit Amount under the Construction and Funding Agreement	851,296
Principal balance outstanding on the Refinery Loan	$ 9,298,183

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9. Concentration of Risk (Tables)

3 Months Ended

Mar. 31, 2013

Concentration Of Risk Tables

Percentages of all refined petroleum products sales to total sales

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

	March 31,			March 31,
	2013			2012
Low-sulfur diesel		51.7	%		86.3	%
Naphtha		26.2	%		7.3	%
Atmospheric gas oil		22.1	%		6.4	%
		100.0	%		100.0	%

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6. Business Segment Information (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013
Segment Reporting [Abstract]
Cost of refined products sold realized loss	$ 36,440
Cost of refined products sold unrealized gain	$ 188,150

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17. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Accrued Expenses And Other Current Liabilities Details
Excise taxes	$ 254,549	$ 292,303
Salaries	109,717	134,501
Turnaround expenses	141,406
Transportation		69,551
Other payable	37,605
Property taxes	13,500
Insurance	57,492
Unrealized hedging loss	188,150	136,100
Unearned revenue	92,783	92,783
Accrued Expenses and Other Current Liabilities, Net	$ 895,202	$ 725,238

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11. Deposits (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Deposits Details
Utility deposits	$ 36,500	$ 36,500
Equipment deposits	124,526	124,526
Tax bonds	792,000	792,000
Purchase option deposits	283,421	283,421
Rent deposits	9,463
Deposits	$ 1,245,910	$ 1,236,447

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25. Stock Options (Tables)

3 Months Ended

Mar. 31, 2013

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

Stock options activity table

At March 31, 2013, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at March 31, 2013		14,642	$	19.67		0.6	$	-
Options exercisable at March 31, 2013		14,642	$	19.67		0.6	$	-

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3. Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these audited 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 $27,348 and $89,593 at March 31, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $0 and $170,896 at March 31, 2013 and December 31, 2012, respectively.

We had four customers that accounted for approximately 81% of our total revenue for the three months ended March 31, 2013. These four customers represented approximately $7.5 million of accounts receivable at March 31, 2013.

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

We utilize an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. 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. 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 FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012. The estimated fair values of our AROs related to our oil and gas properties were recorded at February 15, 2012 in connection with our acquisition of LE.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets for the twelve months ended December 31, 2012, we record pipelines and facilities assets at the lower of cost or net realizable value.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded at February 15, 2012 in connection with our acquisition of LE.

Construction in Progress. Construction in progress expenditures related to refurbishment activities at our petroleum refinery located in Nixon, Wilson County, Texas (the “Nixon Facility”) are capitalized as incurred. Depreciation begins once the asset is placed in service.

Intangibles – Goodwill and Other

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

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

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

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

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill for the twelve months ended December 31, 2012.  The impairment recognized for the twelve months ended December 31, 2012 represented 100% of goodwill.

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

Debt Issue Costs

We have debt issue costs related to certain of our debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations.

Debt issue costs, net of accumulated amortization, totaled $523,885 and $532,335 at March 31, 2013 and December 31, 2012, respectively.  Accumulated amortization was $152,095 and $143,645 at March 31, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Loan.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2013 and 2012.  See “Note (16) Notes Payable” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including naphtha, distillates and atmospheric gas oil. Revenue from refined product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

Customer assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at March 31, 2013 was not material.

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

Income Taxes

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (22) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Future asset retirement costs include costs to dismantle, relocate or dispose of our offshore platform, pipeline systems and related onshore facilities, plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on a quarterly basis.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical volumes are not exchanged and these contracts are net settled with cash. We recognize all commodity hedge transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold using mark-to-market accounting.

Computation of Earnings Per Share

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

The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS (“EPS”) is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock and similar instruments is dependent on this average stock price and will increase as the average stock price increases.

Stock Based Compensation

In accordance with FASB ASC guidance for stock based compensation, share-based payments to employees, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in the consolidated statement of income over the service period (generally the vesting period).

Treasury Stock

We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our Condensed Consolidated Balance Sheets.

Business Combinations

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

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

Reclassification

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation. The most significant of these reclassifications consisted of an increase in cost of refined products sold, and a corresponding decrease in refinery operating expenses.

Recently Adopted Accounting Guidance

In July 2012, FASB amended ASC guidance related to intangibles, goodwill and other. This amendment is intended to reduce the cost and complexity of the annual impairment test for indefinite-lived intangible assets other than goodwill by providing entities an option to perform a qualitative assessment to determine whether further impairment testing is necessary. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. We adopted this guidance in 2012.  The adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

New Pronouncements Issued but Not Yet Effective

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

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12. Inventories (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 972,943	$ 397,240
Naphtha	2,210,804	1,562,055
Atmospheric gas oil	587,004	322,356
Crude	19,041	19,041
Inventories, Net	$ 3,789,792	$ 2,300,692

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17. Accrued Expenses and Other Current Liabilities (Tables)

3 Months Ended

Mar. 31, 2013

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consisted of the following:

	March 31,		December 31,
	2013		2012
Excise taxes	$	254,549	$	292,303
Salaries		109,717		134,501
Turnaround expenses		141,406		-
Transportation		-		69,551
Other payable		37,605		-
Property taxes		13,500		-
Insurance		57,492		-
Unrealized hedging loss		188,150		136,100
Unearned revenue		92,783		92,783
	$	895,202	$	725,238

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23. Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Management Agreement

See “Note (15) Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Genesis Agreements

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

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. 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, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement 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;

● Joint Marketing Agreement -- The Joint Marketing Agreement sets forth the terms of the agreement between LE and GEL pursuant to which the parties will market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil pursuant to the Crude Supply Agreement) as follows:

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

(b) Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any Accounting Fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.

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

(d) Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.

(e) After the Threshold Date, if GEL sustains losses, it can recoup those losses by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated.

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any 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 was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

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

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

(c) In February 2013, Milam paid a vendor $64,357.50 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees.  In addition, Milam and GEL incurred legal fees and expenses related to settling the matter.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

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

As of March 31, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,145,584. As of March 31, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $851,296.

As of March 31, 2013, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the three months ended March 31, 2013, no payments were made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits.

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

In June 2012, we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LTRI, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.

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

Lazarus Energy Development, LLC (“LED”) Option

In February 2012 we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option.

Legal Matters

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

Environmental Matters

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

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22. Income Taxes

3 Months Ended

Mar. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

LE is a limited liability company and, prior to our acquisition of LE, its taxable income or loss flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon LE's acquisition, LE became the 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 LE acquisition, Section 382 of the Internal Revenue Code imposes a limitation on the use Blue Dolphin’s NOLs.  The amount of NOLs subject to such limitations is approximately $18.5 million. The NOL generated subsequent to the LE acquisition, approximately $6.4 million, is not subject to any such limitation. For the three months ended March 31, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

Income tax expense was $0 and $30,563 for the three months ended March 31, 2013 and 2012, respectively. Income tax expense related to state income tax.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax. At March 31, 2013, we accrued $0 in TMT.

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts, USD $)	Mar. 31, 2013	Dec. 31, 2012
Commodity Contracts
Accrued expenses and other current liabilities	$ 188,150	$ 136,100

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18. Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

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

Asset retirment obligations as of December 31, 2012	$	921,260
Accretion expense		25,164
		946,424
Less:  current portion of asset retirement obligations		90,601
Asset retirement obligations, long-term balance
at March 31, 2013	$	855,823

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24. Earnings Per Share

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

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

	Three Months Ended March 31,
	2013			2012
Loss from continuing operations, net of tax	$	(763,331	)	$	(1,957,380	)
Loss from discontinued operations, net of tax		-			(12,514	)
Net loss		(763,331	)		(1,969,894	)
Basic and diluted loss per common share
Continuing operations	$	(0.07	)	$	(0.37	)
Discontinued operations	$	-		$	-
Basic and diluted loss per common share	$	(0.07	)	$	(0.37	)
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,510,334			5,261,328

Diluted EPS is computed by dividing net loss available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2013 and 2012 excludes stock options outstanding as they would be anti-dilutive.

For the three months ended March 31, 2012, the weighted average number of shares of common stock outstanding was computed as LE’s number of shares of common stock outstanding from January 1, 2012 to February 15, 2012 (the beginning of the period to the date of LE’s acquisition by Blue Dolphin) combined with Blue Dolphin’s number of shares of common stock outstanding from February 15, 2012 to March 31, 2012 (the date of LE’s acquisition by Blue Dolphin to the end of the period).  For the period prior to the date of LE’s acquisition by Blue Dolphin, LE’s number of shares of common stock was computed as LE’s one member unit prior to the acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

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25. Stock Options

3 Months Ended

Mar. 31, 2013

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

Stock Options

Our 2000 Stock Incentive 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 Compensation Committee of the Board of Directors (the “Board”) approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

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

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the three months ended March 31, 2013.

At March 31, 2013, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at March 31, 2013		14,642	$	19.67		0.6	$	-
Options exercisable at March 31, 2013		14,642	$	19.67		0.6	$	-

We recognized no compensation expense for vested stock options for the three months ended March 31, 2013 and 2012. As of March 31, 2013, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the three months ended March 31, 2013, we recognized $50,000 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

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2. Basis of Presentation

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Basis of Presentation

We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (14) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

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3. Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Basis of presentation

We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the condensed consolidated financial statements. See “Note (14) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these audited 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 $27,348 and $89,593 at March 31, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $0 and $170,896 at March 31, 2013 and December 31, 2012, respectively.

We had four customers that accounted for approximately 81% of our total revenue for the three months ended March 31, 2013. These four customers represented approximately $7.5 million of accounts receivable at March 31, 2013.

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

We utilize an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. 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. 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 FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012. The estimated fair values of our AROs related to our oil and gas properties were recorded at February 15, 2012 in connection with our acquisition of LE.

Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets for the twelve months ended December 31, 2012, we record pipelines and facilities assets at the lower of cost or net realizable value.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded at February 15, 2012 in connection with our acquisition of LE.

Construction in Progress. Construction in progress expenditures related to refurbishment activities at our petroleum refinery located in Nixon, Wilson County, Texas (the “Nixon Facility”) are capitalized as incurred. Depreciation begins once the asset is placed in service.

Intangibles - Goodwill and Other

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

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

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

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

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill for the twelve months ended December 31, 2012.  The impairment recognized for the twelve months ended December 31, 2012 represented 100% of goodwill.

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

Debt Issue Costs

We have debt issue costs related to certain of our debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations.

Debt issue costs, net of accumulated amortization, totaled $523,885 and $532,335 at March 31, 2013 and December 31, 2012, respectively.  Accumulated amortization was $152,095 and $143,645 at March 31, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Loan.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2013 and 2012.  See “Note (16) Notes Payable” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including naphtha, distillates and atmospheric gas oil. Revenue from refined product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

Customer assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

Tank Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at March 31, 2013 was not material.

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

Income Taxes

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a tax benefit will not be realized.

The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (22) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Future asset retirement costs include costs to dismantle, relocate or dispose of our offshore platform, pipeline systems and related onshore facilities, plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on a quarterly basis.

Derivatives

We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our refined petroleum products and crude oil inventory risk management policy.  Under the refined petroleum products and crude oil inventory risk management policy, Genesis uses commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations. The physical volumes are not exchanged and these contracts are net settled with cash. We recognize all commodity hedge transactions as either current assets or current liabilities in the consolidated balance sheets and those instruments are measured at fair value. Therefore, changes in the fair value of these commodity hedging instruments are included in income in the period of change. Net gains or losses associated with these transactions are recognized within cost of products sold using mark-to-market accounting.

Computation of Earnings Per Share

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

The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS (“EPS”) is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock and similar instruments is dependent on this average stock price and will increase as the average stock price increases.

Stock Based Compensation

In accordance with FASB ASC guidance for stock based compensation, share-based payments to employees, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in the consolidated statement of income over the service period (generally the vesting period).

Treasury Stock

We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our Condensed Consolidated Balance Sheets.

Business Combinations

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

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

Reclassification

Certain reclassifications have been made to the prior year’s condensed consolidated financial statements in order to conform to the current year’s presentation. The most significant of these reclassifications consisted of an increase in cost of refined products sold, and a corresponding decrease in refinery operating expenses.

Recently Adopted Accounting Guidance

In July 2012, FASB amended ASC guidance related to intangibles, goodwill and other. This amendment is intended to reduce the cost and complexity of the annual impairment test for indefinite-lived intangible assets other than goodwill by providing entities an option to perform a qualitative assessment to determine whether further impairment testing is necessary. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. We adopted this guidance in 2012.  The adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

New Pronouncements Issued but Not Yet Effective

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

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12. Inventories (Tables)

3 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Inventories balances

Inventory balances consisted of the following:

	March 31,		December 31,
	2013		2012
Low-sulfur diesel	$	972,943	$	397,240
Naphtha		2,210,804		1,562,055
Atmospheric gas oil		587,004		322,356
Crude		19,041		19,041
	$	3,789,792	$	2,300,692

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7. Fair Value Measurement (Details) (USD $)	Mar. 31, 2013
Financial liabilties:
Commodity contracts	$ 188,150
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	188,150
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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20. Leases (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Leases Details Narrative
Rent expense	$ 29,041	$ 28,344

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 88,059	$ 420,896
Restricted cash	27,348	89,593
Accounts receivable, net	10,510,790	15,398,755
Prepaid expenses and other current assets	208,959	228,314
Deposits	1,245,910	1,236,447
Inventory	3,789,792	2,300,692
Total current assets	15,870,858	19,674,697
Total property and equipment, net	36,063,523	35,862,085
Debt issue costs, net	523,885	532,335
Other assets		9,463
Trade name	303,346	303,346
TOTAL ASSETS	52,761,612	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	16,292,668	19,171,013
Accounts payable, related party	2,178,061	1,594,021
Note payable	9,348,518	43,941
Asset retirement obligations, current portion	90,601
Accrued expenses and other current liabilities	895,202	725,238
Interest payable, current portion	637,551	640,352
Long-term debt, current portion	1,485,000	1,816,960
Total current liabilities	30,927,601	23,991,525
Asset retirement obligations, net of current portion	855,823	921,260
Long term debt, net of current portion	4,960,584	13,989,517
Long term interest payable, net of current portion	910,071	858,784
Total long-term liabilities	6,726,478	15,769,561
TOTAL LIABILITIES	37,654,079	39,761,086
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,571,629 and 10,563,297 shares issued at March 31, 2013 and December 31, 2012, respectively)	105,717	105,633
Additional paid-in capital	36,574,059	36,524,142
Accumulated deficit	(20,772,243)	(20,008,935)
Treasury stock, 150,000 and 0 shares, respectively, at cost	(800,000)
Total stockholders' equity	15,107,533	16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 52,761,612	$ 56,381,926

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19. Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2012

Debt Disclosure [Abstract]

Long Term Debt

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

	March 31,		December 31,
	2013		2012
Refinery Loan	$	-	$	9,298,183
Notre Dame Debt		1,300,000		1,300,000
Construction Funding		5,145,584		5,206,175
Captial Leases		-		2,119
		6,445,584		15,806,477
Less: Current portion of long-term debt		1,485,000		1,816,960
	$	4,960,584	$	13,989,517

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Condensed Consolidated Statements of Cash Flows (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Cash Flows [Abstract]
Cash acquired from business acquisition	$ 1,674,594	$ 1,674,594

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9. Concentration of Risk (Details Narrative)	3 Months Ended
	Mar. 31, 2013
Concentration Of Risk Details Narrative
Four largest customers representation in sales	81.00%

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7. Fair Value Measurement (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurement

			Fair Value Measurement at March 31, 2013 Using
Financial liabilities:	Carrying Value as at March 31, 2013		'Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		'Significant Other Observable Inputs (Level 2)		'Significant Unobservable Inputs (Level 3)
Commodity contracts	$	188,150	$	188,150	$	-	$	-

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15. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Payables and Accruals [Abstract]
Expense for service	$ 2,745,209	$ 1,062,751
Accounts payable, related party	$ 2,178,061		$ 1,594,021

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16. Note Payable

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Note Payable

Notes payable at March 31, 2013 and December 31, 2012 was $9,348,518 and $43,941, respectively. The Refinery Loan portion of notes payable at March 31, 2013 and December 31, 2012 was $9,298,183 and $0, respectively.

Refinery Loan.  In September 2008, LE obtained a loan from First International Bank (“FIB”) in the amount of $10,000,000 (the “Refinery Loan”).  The Refinery Loan accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at March 31, 2013) and has a maturity date of October 2028.  The Refinery Loan is: (i) secured by a first lien on the Nixon Facility and general assets of LE and (ii) subject to certain restrictive financial covenants related to debt to net worth and current ratio.  Currently, we are not in compliance with certain financial covenants and, since August 2011, the Refinery Loan has been subject to a forbearance agreement (the “Forbearance Agreement”). Interest was accrued on the Refinery Loan in the amount of $178,646 and $250,070 at March 31, 2013 and December 31, 2012, respectively.

The Forbearance Agreement provides for a reduced minimum monthly payment on the Refinery Loan of $60,000.  The initial forbearance period under the Forbearance Agreement commenced in August 2011 and ended in August 2012 (the “Initial Forbearance Period”) with an additional one year extension period beyond the Initial Forbearance Period ending on August 12, 2013 (the “Extended Forbearance Period” and together with the Initial Forbearance Period, the “Forbearance Period”), if we satisfied certain conditions.  In October 2011, the Refinery Loan and its related security documents (the “Refinery Loan Documents”) were acquired by American First National Bank (“AFNB”).  In June 2012, AFNB sent a letter to LE outlining what AFNB believed to be contraventions to certain provisions of the Refinery Loan, the Refinery Loan Documents and the Forbearance Agreement, including an assertion that Blue Dolphin’s acquisition of LE represented a change of control of LE, resulting in a default under the Refinery Loan.  We responded to AFNB expressing a belief that LE was in compliance with provisions of the Refinery Loan Documents.  In December 2012, AFNB sent a letter to LE confirming that LE was in compliance with the provisions of the Refinery Loan Documents, and providing for an extension of the Forbearance Agreement through the Extended Forbearance Period.

During the Forbearance Period, we remain subject to the terms, conditions and covenants of the Refinery Loan, other than those that our compliance with is expressly waived by the Forbearance Agreement.  Further, AFNB may terminate the Forbearance Agreement and any extensions thereof at any time if any of the following events (the “Termination Events”) occur:

● We do not, upon the Nixon Facility becoming operational, and the cessation of the payment of tank storage fees by Genesis to us, make the required minimum monthly payment to AFNB;

● 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 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 has a receiver or similar official appointed.

As of the date of filing of this report, no Termination Events have occurred.

After all past due principal and interest (as well as costs, fees and taxes) have been paid, AFNB will: (i) re-amortize the Refinery Loan to the original maturity date of October 1, 2028 and (ii) apply twelve consecutive additional monthly payments in the amount of $83,333.33 towards replenishing the $1,000,000 payment reserve required under the Refinery Loan in accordance with the Forbearance Agreement.

Short-Term Note for Financing Costs.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing costs was $34,866 and $39,866 at March 31, 2013 and December 31, 2012, respectively.  The unsecured note, which bears interest at 18% and was originally due in January 2012, has been extended to June 2013. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $15,469 and $0 at March 31, 2013 and December 31, 2012, respectively.  In January 2013 we acquired a pressure washer under an interest-free, short-term capital lease.  We also reclassified capital leases from long-term debt at December 31, 2012 to short-term debt at March 31, 2013 as they mature at various dates through February 2014.  These capital leases have interest rates ranging from 0% to 13.04%.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

The balance on a short-term note related to previously owned trucks for use at the Nixon Facility was $0 and $4,075 at March 31, 2013 and December 31, 2012, respectively.  The unsecured note bore interest at 5%.

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8. Refined Products Inventory Risk Management (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

As of March 31, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -  net short (long) positions		50,000		-		-		-

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

		Fair Value
Liabilities Derivatives	Balance Sheets Location	March 31, 2013		December 31, 2012
Commodity contracts	Accrued expenses and other current liabilities	$	188,150	$	136,100

The following table provides the effect of derivative instruments on the consolidated statements of operations for the three months ended h 31, 2013 and 2012: 

		Gain (Loss) Recognized
Derivatives	Statements of Operations Location	March 31, 2013			March 31, 2012
Commodity contracts	Cost of refined products sold	$	(188,150	)	$	-

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18. Asset Retirement Obligations

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Refinery and Facilities

Management has concluded that there is no legal or contractual obligation to dismantle or remove our refinery and facilities assets. Management believes that our refinery and facilities assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.

Oil and Gas Properties and Pipelines and Facilities Assets

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

Asset retirment obligations as of December 31, 2012	$	921,260
Accretion expense		25,164
		946,424
Less:  current portion of asset retirement obligations		90,601
Asset retirement obligations, long-term balance
at March 31, 2013	$	855,823

Actual plugging and abandonment expenses associated with HI-A7 have exceeded the estimated ARO liability. Additional plugging and abandonment expenses associated with HI-A7 will be recognized as a loss in the period incurred. For the three months ended March 31, 2013, we recognized $27,451 in abandonment expense for AROs associated with HI-A7. We will record additional plugging and abandonment costs for HI-A7 as information becomes available from the operator, Apache Corp., to substantiate actual and/or probable costs.

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18. Asset Retirement Obligations (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Asset Retirement Obligations Details
Fair value of asset retirement obligations at December 31, 2012	$ 921,260
Accretion expense	25,164	21,561
Asset retirement obligations as of March 31, 2013	946,424
Less current portion of asset retirement obligations	90,601
Asset retirement obligations, long-term balance at March 31, 2013	$ 855,823		$ 921,260

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1. Organization

3 Months Ended

Mar. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company. We are primarily an independent refiner and marketer of petroleum products.  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (6) Business Segment Information” for further discussion of our business segments.

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

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

·   Lazarus Refining & Marketing, LLC (“LRM”), a Delaware limited liability company (petroleum storage and terminaling);

·   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 (“BDEX”), a Delaware corporation (exploration and production investment); and

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

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,571,629	10,563,297
Common stock, shares outstanding	10,571,629	10,563,297

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11. Deposits

3 Months Ended

Mar. 31, 2013

Banking and Thrift [Abstract]

Deposits

Deposit balances consisted of the following:

	March 31,		December 31,
	2013		2012
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
Deposits	$	1,245,910	$	1,236,447

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Document and Entity Information (USD $)	3 Months Ended
	Mar. 31, 2013	May 15, 2013
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float		$ 105,716
Entity Common Stock, Shares Outstanding		10,571,629
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2013

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12. Inventories

3 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Inventory balances consisted of the following:

	March 31,		December 31,
	2013		2012
Low-sulfur diesel	$	972,943	$	397,240
Naphtha		2,210,804		1,562,055
Atmospheric gas oil		587,004		322,356
Crude		19,041		19,041
	$	3,789,792	$	2,300,692

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
REVENUE FROM OPERATIONS
Refined product sales	$ 109,171,507	$ 45,770,963
Pipeline operations	73,148	69,910
Oil and gas sales		6,056
Total revenue from operations	109,244,655	45,846,929
COST OF OPERATIONS
Cost of refined products sold	106,322,661	45,641,226
Refinery operating expenses	2,745,209	1,062,751
Pipeline operating expenses	45,371	109,618
Lease operating expenses	26,901	19,338
General and administrative expenses	484,564	525,587
Depletion, depreciation and amortization	328,788	255,753
Abandonment expense	27,451
Accretion expense	25,164	21,561
Total cost of operations	110,006,109	47,635,834
Loss from operations	(761,454)	(1,788,905)
OTHER INCOME (EXPENSE)
Net tank rental revenue	278,350	93,955
Interest and other income	835	1,650
Interest expense	(281,063)	(233,517)
Total other expense	(1,878)	(137,912)
Loss from continuing operations before income taxes	(763,331)	(1,926,817)
Tax expense Current		(30,563)
Tax expense Deferred
Income tax expense	0	(30,563)
Loss from continuing operations, net of tax	(763,331)	(1,957,380)
Loss from discontinued operations, net of tax		(12,514)
Net loss	$ (763,331)	$ (1,969,894)
Basic loss per common share
Continuing operations	$ (0.07)	$ (0.21)
Discontinued operations
Basic loss per common share	$ (0.07)	$ (0.21)
Diluted loss per common share
Continuing operations	$ (0.07)	$ (0.21)
Discontinued operations
Diluted loss per common share	$ (0.07)	$ (0.21)
Weighted average number of common shares outstanding:
Basic	10,510,334	9,476,748
Diluted	10,510,334	9,476,748

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6. Business Segment Information

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Business Segment Information

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

Segment financials for the three months ended March 31, 2013 (and at March 31, 2013) were as follows:

	Three Months Ended March 31, 2013
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	109,171,507		$	73,148		$	-		$	-		$	109,244,655
Less:  Operation cost(2)		(109,063,677	)		(96,835	)		(57,664	)		(459,146	)		(109,677,321	)
Other non-interest income		278,350			-			-			-			278,350
EBITDA	$	386,180		$	(23,686	)	$	(57,664	)	$	(459,146	)
Depletion, depreciation and amortization														(328,788	)
Other income (expense), net														(280,228	)
Loss from continuing operations,
before income taxes													$	(763,331	)
Loss from discontinued operations													$	-
Capital expenditures	$	530,226		$	-		$	-		$	-		$	530,226
Identifiable assets(3)	$	50,131,322		$	1,628,612		$	33,773		$	967,906		$	52,761,612

___________________________________

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $36,440 and an unrealized gain of $188,150.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the three months ended March 31, 2012 (and at March 31, 2012) were as follows:

	Three Months Ended March 31, 2012
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	45,770,963		$	69,910		$	6,056		$	-		$	45,846,929
Less:  Operation cost(2)		(46,862,438	)		(195,717	)		(204,287	)		(117,639	)		(47,380,081	)
Other non-interest income		93,955			-			-			-			93,955
EBITDA	$	(997,520	)	$	(125,807	)	$	(198,231	)	$	(117,639	)
Depletion, depreciation and amortization														(255,753	)
Other income (expense), net														(231,867	)
Loss from continuing operations,
before income taxes													$	(1,926,817	)
Loss from discontinued operations													$	(12,514	)
Capital expenditures	$	1,349,332		$	-		$	-		$	-		$	1,349,332
Identifiable assets(3)	$	56,220,025		$	12,567,746		$	5,605,448		$	1,123,919		$	75,517,138

_____________________

(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. LRM Acquisition

3 Months Ended

Mar. 31, 2013

Insurance [Abstract]

LRM Acquisition

Effective October 1, 2012, we acquired 100% of the issued and outstanding membership interest of LRM, a wholly-owned subsidiary of LEH pursuant to an Assignment Agreement. The acquisition was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of LRM were transferred at their carrying amounts at the date of transfer and the results of operations are included in our financial results for the three months ended March 31, 2013. LRM did not have significant assets, liabilities or results of operations for the three months ended March 31, 2013. Assets and liabilities included in the consolidated balance sheets were $30,082 and $496,716, respectively, as of March 31, 2013. LRM markets petroleum storage and terminaling services at the Nixon Facility

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17. Accrued Expenses and Other Current Liabilities

3 Months Ended

Mar. 31, 2013

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	March 31,		December 31,
	2013		2012
Excise taxes	$	254,549	$	292,303
Salaries		109,717		134,501
Turnaround expenses		141,406		-
Transportation		-		69,551
Other payable		37,605		-
Property taxes		13,500		-
Insurance		57,492		-
Unrealized hedging loss		188,150		136,100
Unearned revenue		92,783		92,783

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13. Property, Plant and Equipment, Net

3 Months Ended

Mar. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	March 31,		December 31,
	2013		2012
Refinery and facilities	$	34,384,328	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		629,424		577,567
		37,150,964		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,002,938		1,674,151
		35,148,025		35,040,826
Construction in Progress		915,497		821,259
Property, Plant and Equipment, Net	$	36,063,523	$	35,862,085

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9. Concentration of Risk

3 Months Ended

Mar. 31, 2013

Risks and Uncertainties [Abstract]

Concentration of Risk

Key Supplier. GEL TEX Marketing, LLC (“GEL”) is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2014.

Significant Customers. Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. For the three months ended March 31, 2013, our four largest customers accounted for approximately 81% of our refined petroleum products sales.

Remainder of Page Intentionally Left Blank

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

	March 31,			March 31,
	2013			2012
Low-sulfur diesel		51.7	%		86.3	%
Naphtha		26.2	%		7.3	%
Atmospheric gas oil		22.1	%		6.4	%
		100.0	%		100.0	%

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10. Prepaid Expenses and Other Current Assets (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 138,959	$ 185,814
Prepaid restructing fees	50,000
Employee advances		22,500
Prepaid loan closing fees	20,000	20,000
Prepaid Expenses, Net	$ 208,959	$ 228,314

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7. Fair Value Measurement

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurement

We are subject to gains or losses on certain financial assets based on our various agreements and understandings with Genesis. Pursuant to these agreements and understandings, Genesis can execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity risks associated with our refined petroleum products and crude oil inventory and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil inputs. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreements with Genesis, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments by Genesis. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded derivatives in our books and records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions executed on our behalf involving identical or comparable assets or liabilities.

The fair value hierarchy consists of the following three levels:

Level 1	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2	Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data.
Level 3	Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs.

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at March 31, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our longer term debt at March 31, 2013 and December 31, 2012 was $15,743,767 and $15,806,477, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2013 and the basis for that measurement:

			Fair Value Measurement at March 31, 2013 Using
Financial liabilities:	Carrying Value as at March 31, 2013		'Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		'Significant Other Observable Inputs (Level 2)		'Significant Unobservable Inputs (Level 3)
Commodity contracts	$	188,150	$	188,150	$	-	$	-

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

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products and Crude Oil Inventory Risk Management

Under our refined petroleum products and crude oil inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for a portion of our inventory volumes subject to market price fluctuations in our inventory. The physical volumes are not exchanged, and these contracts are net settled by Genesis with cash.

The fair value of these contracts is reflected in the consolidated balance sheets and the related net gain or loss is recorded within cost of refined petroleum products sold in the consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end.

Commodity transactions are executed by Genesis to minimize transaction costs, monitor consolidated net exposures and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products and crude oil when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a futures contract is made solely by Genesis, Genesis typically confers with management as part of their decision making process.

Due to mark-to-market accounting during the term of the commodity contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations. Additionally, Genesis may be required to collateralize any mark-to-market losses on outstanding commodity contracts.

As of March 31, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2013		2014		2015		2016
Refined petroleum products and crude oil -  net short (long) positions		50,000		-		-		-

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

		Fair Value
Liabilities Derivatives	Balance Sheets Location	March 31, 2013		December 31, 2012
Commodity contracts	Accrued expenses and other current liabilities	$	188,150	$	136,100

The following table provides the effect of derivative instruments on the consolidated statements of operations for the three months ended h 31, 2013 and 2012: 

		Gain (Loss) Recognized
Derivatives	Statements of Operations Location	March 31, 2013			March 31, 2012
Commodity contracts	Cost of refined products sold	$	(188,150	)	$	-

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10. Prepaid Expenses and Other Current Assets

3 Months Ended

Mar. 31, 2013

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

Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	March 31,		December 31,
	2013		2012
Prepaid insurance	$	138,959	$	185,814
Prepaid restructing fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		20,000		20,000
	$	208,959	$	228,314

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14. Discontinued Operations (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenue	$ 109,244,655	$ 45,846,929
Depletion, depreciation and amortization	328,788	255,753
Loss from discontinued operations, net of tax		(12,514)
Discontinued Operations
Revenue		194,284
Lease operating expenses		182,375
Depletion, depreciation and amortization		22,209
Accretion expense		2,214
Total costs and expenses		206,798
Loss from discontinued operations, net of tax		$ (12,514)

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16. Note Payable (Details Narrative) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Short-term note	$ 34,866	$ 39,866
Note payable	9,348,518	43,941
Short-term notes under capital lease agreements	15,469	0
Balance on a short-term note related to previously owned trucks	$ 0	$ 4,075

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13. Property, Plant and Equipment, Net (Details) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Property Plant And Equipment Net Details
Refinery and facilities	$ 34,384,328	$ 34,000,199
Pipelines and facilities	1,233,811	1,233,811
Onshore separation and handling facilities	325,435	325,435
Land	577,965	577,965
Other property and equipment	629,424	577,567
Property, Plant and Equipment, Gross	37,150,964	36,714,977
Less: Accumulated depletion, depreciation and amortization	2,002,938	1,674,151
Property, Plant and Equipment less depreciation	35,148,025	35,040,826
Construction in Progress	915,497	821,259
Property, Plant and Equipment, Net	$ 36,063,523	$ 35,862,085

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6. Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Business segment reporting

Segment financials for the three months ended March 31, 2013 (and at March 31, 2013) were as follows:

	Three Months Ended March 31, 2013
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	109,171,507		$	73,148		$	-		$	-		$	109,244,655
Less:  Operation cost(2)		(109,063,677	)		(96,835	)		(57,664	)		(459,146	)		(109,677,321	)
Other non-interest income		278,350			-			-			-			278,350
EBITDA	$	386,180		$	(23,686	)	$	(57,664	)	$	(459,146	)
Depletion, depreciation and amortization														(328,788	)
Other income (expense), net														(280,228	)
Loss from continuing operations,
before income taxes													$	(763,331	)
Loss from discontinued operations													$	-
Capital expenditures	$	530,226		$	-		$	-		$	-		$	530,226
Identifiable assets(3)	$	50,131,322		$	1,628,612		$	33,773		$	967,906		$	52,761,612

___________________________________

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations group. Cost of refined products sold includes a realized loss of $36,440 and an unrealized gain of $188,150.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the three months ended March 31, 2012 (and at March 31, 2012) were as follows:

	Three Months Ended March 31, 2012
	Segment
							Oil and Gas
	Refinery			Pipeline			Exploration &			Corporate &
	Operations			Transportation			Production			Other(1)			Total
Revenues	$	45,770,963		$	69,910		$	6,056		$	-		$	45,846,929
Less:  Operation cost(2)		(46,862,438	)		(195,717	)		(204,287	)		(117,639	)		(47,380,081	)
Other non-interest income		93,955			-			-			-			93,955
EBITDA	$	(997,520	)	$	(125,807	)	$	(198,231	)	$	(117,639	)
Depletion, depreciation and amortization														(255,753	)
Other income (expense), net														(231,867	)
Loss from continuing operations,
before income taxes													$	(1,926,817	)
Loss from discontinued operations													$	(12,514	)
Capital expenditures	$	1,349,332		$	-		$	-		$	-		$	1,349,332
Identifiable assets(3)	$	56,220,025		$	12,567,746		$	5,605,448		$	1,123,919		$	75,517,138

_____________________

(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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6. Business Segment Information (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues	$ 109,244,655	$ 45,846,929
Depletion, depreciation and amortization	328,788	255,753
Loss from discontinued operations		(12,514)
Refinery Operations Member
Revenues	109,171,507	45,770,963
Operation cost	(109,063,677)	(46,862,438)
Other non-interest income	278,350	93,955
EBITDA	386,180	(997,520)
Capital expenditures	530,226	1,349,332
Identifiable assets	50,131,322	56,220,025
Pipeline Transportation
Revenues	73,148	69,910
Operation cost	(96,835)	(195,717)
Other non-interest income
EBITDA	(23,686)	(125,807)
Capital expenditures
Identifiable assets	1,628,612	12,567,746
Oil And Gas Exploration and Production
Revenues		6,056
Operation cost	(57,664)	(204,287)
Other non-interest income
EBITDA	(57,664)	(198,231)
Capital expenditures
Identifiable assets	33,773	5,605,448
Corporate and Other
Revenues
Operation cost	(459,146)	(117,639)
Other non-interest income
EBITDA	(459,146)	(117,639)
Capital expenditures
Identifiable assets	967,906	1,123,919
Total
Revenues	109,244,655	45,846,929
Operation cost	(109,677,321)	(47,380,081)
Other non-interest income	278,350	93,955
Depletion, depreciation and amortization	(328,788)	(255,753)
Other income (expense), net	(280,228)	(231,867)
Income (loss) before taxes	(763,331)	(1,926,817)
Loss from discontinued operations		(12,514)
Capital expenditures	530,226	1,349,332
Identifiable assets	$ 52,761,612	$ 75,517,138

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15. Accounts Payable, Related Party

3 Months Ended

Mar. 31, 2013

Payables and Accruals [Abstract]

Accounts Payable, Related Party

LEH, which owns approximately 80% of our 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”).

Under the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and 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.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended March 31, 2013 and March 31, 2012 were $2,745,209 (approximately $2.80 per barrel) and $1,062,751 (approximately $2.72 per barrel). At March 31, 2013 and December 31, 2012, the amounts outstanding to LEH were $2,178,061 and $1,594,021, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets.

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

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20. Leases

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month.  The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. Rent expense for the office lease was $29,041 and $28,344 for the three months ended March 31, 2013 and 2012, respectively.

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4. LE Acquisition (Details) (USD $)	Mar. 31, 2013	Feb. 15, 2012 As Reported	Feb. 15, 2012 Adjustments	Feb. 15, 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	946,424		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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13. Property, Plant and Equipment, Net (Tables)

3 Months Ended

Mar. 31, 2013

Property, Plant and Equipment [Abstract]

Property and equipment

Property and equipment consisted of the following:

	March 31,		December 31,
	2013		2012
Refinery and facilities	$	34,384,328	$	34,000,199
Pipelines and facilities		1,233,811		1,233,811
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		629,424		577,567
		37,150,964		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,002,938		1,674,151
		35,148,025		35,040,826
Construction in Progress		915,497		821,259
Property, Plant and Equipment, Net	$	36,063,523	$	35,862,085

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
OPERATING ACTIVITIES
Net loss	$ (763,331)	$ (1,969,894)
Loss from discontinued operations		12,514
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	328,788	252,898
Unrealized loss on derivatives	52,050
Amortization of debt issue costs	8,450	8,449
Amortization of intangible assets	9,463	2,855
Accretion expense	25,164	21,561
Abandonment costs incurred	27,451	(110)
Common stock issued for services	50,000	20,000
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash	62,245	(151)
Accounts receivable	4,087,965	(15,923,454)
Prepaid expenses and other current assets	19,355	(57,513)
Deposits	(9,463)	(667,421)
Inventory	(1,489,100)	(554,441)
Accounts payable, accrued expenses and other liabilities	(2,739,371)	16,010,675
Accounts payable, related party	584,040	1,253,764
Net cash provided by (used in) operating activities - continuing operations	253,705	(1,590,268)
Net cash provided by operating activities - discontinued operations		11,909
Net cash provided by (used in) operating activities	253,705	(1,578,359)
INVESTING ACTIVITIES
Capital expenditures	(530,226)	(1,349,332)
Cash acquired on Acquisition		1,674,594
Net cash provided by (used in) investing activities	(530,226)	325,262
FINANCING ACTIVITIES
Proceeds from issuance of debt		2,364,012
Payments on long term debt	(60,876)	(2,916)
Proceeds from notes payable	15,031
Payments on notes payable	(10,472)
Net cash provided by (used in) financing activities	(56,316)	2,361,096
Net increase (decrease) in cash and cash equivalents	(332,837)	1,107,999
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	420,896	1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	88,059	1,109,821
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	800,000
Non-cash investing and financing activities:
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
Shares issued for services	$ 50,000	$ 40,000

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4. LE Acquisition

3 Months Ended

Mar. 31, 2013

Business Combinations [Abstract]

LE Acquisition

Effective February 15, 2012, we acquired 100% of the issued and outstanding membership interests of LE from Lazarus Energy Holdings, LLC (“LEH”). The acquisition was considered a business combination. As consideration for LE, we 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 Blue Dolphin 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, we 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 the issuance of the BDEC Shares, LEH owns approximately 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 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 180,000 barrels of refined product storage capacity. The Nixon Facility has the capability to produce products such as Non-Road, Locomotive, and Marine Diesel Fuel (“NRLM”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil.

The acquisition of LE was 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) was treated as the accounting parent (acquirer) and Blue Dolphin (the legal parent) was treated as the accounting subsidiary (acquiree).  Accordingly, financial statements presented herein reflect 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 effective date (February 15, 2012).  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 (2,098,390 shares) multiplied by the closing price of Blue Dolphin’s Common Stock on February 15, 2012 ($8.60). As a result, the fair value of Blue Dolphin was $18,046,154.

In connection with the acquisition of LE, we engaged an independent third-party to determine the fair value of 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 below table summarizes the purchase price allocation of the net assets acquired and measurement period adjustments as of the acquisition date (as adjusted). The estimated fair values of the assets acquired and liabilities assumed were based on information that was available as of the acquisition date. Measurement period adjustments for Blue Dolphin were completed during 2012.  Goodwill recognized in the transaction was related to the value expected to be received from the combination of LE’s refinery operations and Blue Dolphin’s pipeline and facilities and operational expertise.

	February 15, 2012 As Intially		Measurement Period			Purchase Price Allocation (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

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9. Concentration of Risk (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Concentration Risk	100.00%	100.00%
Low-sulfur diesel
Concentration Risk	51.70%	86.30%
Naphtha
Concentration Risk	26.20%	7.30%
Atmospheric gas oil
Concentration Risk	22.10%	6.40%

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18. Asset Retirement Obligations (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Asset Retirement Obligations Details Narrative
Abandonment expense	$ 27,451	$ (110)

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21. Treasury Stock

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia.  The non-cash transaction was completed on February 28, 2013.  Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of Common Stock, which represented a recovery of a significant portion of the 342,857 shares of Common Stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  We expect to use the treasury stock to issue restricted Common Stock to our independent directors as compensation for services rendered and for stock option exercises.  As of March 31, 2013, there were 150,000 shares of treasury stock.

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22. Income Taxes (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Income Taxes Details Narrative
Income tax expense	$ 0	$ (30,563)
Accrued Texas margins tax	$ 0

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10. Prepaid Expenses and Other Current Assets (Tables)

3 Months Ended

Mar. 31, 2013

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid balances consisted of the following:

	March 31,		December 31,
	2013		2012
Prepaid insurance	$	138,959	$	185,814
Prepaid restructing fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		20,000		20,000
	$	208,959	$	228,314

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14. Discontinued Operations

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Discontinued Operations

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

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

	March 31,		March 31,
	2013		2012
Revenue	$	-	$	194,284
Lease operating expenses		-		182,375
Depletion, depreciation and amortization		-		22,209
Accretion expense		-		2,214
Total costs and expenses		-		206,798
Loss from discontinued operations, net of tax	$	-	$	(12,514	)