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: June 30, 2013

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

For the transition period from _____________ to_____________

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

(713) 568-4725

(Registrant’s telephone number, including area code)

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

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

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

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

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

Number of shares of common stock, par value $0.01 per share issued and outstanding as of August 13, 2013: 10,571,629.

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

FORM 10-Q REPORT INDEX

PART I. FINANCIAL INFORMATION		3
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	38
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58
ITEM 4.	CONTROLS AND PROCEDURES	58
PART II. OTHER INFORMATION		59
ITEM 1.	LEGAL PROCEEDINGS	59
ITEM 1A.	RISK FACTORS	59
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	59
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	59
ITEM 4.	MINE SAFETY DISCLOSURES	59
ITEM 5.	OTHER INFORMATION	59
ITEM 6.	EXHIBITS	60
SIGNATURES		61

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	180,819		$	420,896
Restricted cash		27,367			89,593
Accounts receivable		8,182,196			15,398,755
Prepaid expenses and other current assets		264,386			228,314
Deposits		1,240,660			1,236,447
Inventory		3,334,114			2,300,692
Total current assets		13,229,542			19,674,697
Total property and equipment, net		35,888,540			35,862,085
Debt issue costs, net		515,435			532,335
Other assets		-			9,463
Trade name		303,346			303,346
TOTAL ASSETS	$	49,936,863		$	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	14,753,545		$	19,171,013
Accounts payable, related party		2,507,422			1,594,021
Notes payable		46,136			43,941
Asset retirement obligations, current portion		85,347			-
Accrued expenses and other current liabilities		713,925			725,238
Interest payable, current portion		577,139			640,352
Long-term debt, current portion		10,741,114			1,816,960
Total current liabilities		29,424,628			23,991,525
Long-term liabilities:
Asset retirement obligations, net of current portion		884,010			921,260
Long-term debt, net of current portion		8,665,775			13,989,517
Long-term interest payable, net of current portion		961,929			858,784
Total long-term liabilities		10,511,714			15,769,561
TOTAL LIABILITIES		39,936,342			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 and outstanding at June 30, 2013 and December 31, 2012, respectively)		105,717			105,633
Additional paid-in capital		36,574,059			36,524,142
Accumulated deficit		(25,879,255	)		(20,008,935	)
Treasury stock, 150,000 shares and 0 shares, respectively, at cost		(800,000	)		-
Total stockholders' equity		10,000,521			16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	49,936,863		$	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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
REVENUE FROM OPERATIONS
Refined product sales	$	104,312,768		$	84,416,296		$	213,484,275		$	130,187,259
Pipeline operations		77,105			124,476			150,253			194,386
Oil and gas sales		-			1,226			-			7,282
Total revenue from operations		104,389,873			84,541,998			213,634,528			130,388,927
COST OF OPERATIONS
Cost of refined products sold		105,871,717			88,051,229			212,194,378			133,692,455
Refinery operating expenses		2,724,644			2,239,914			5,469,853			3,302,665
Pipeline operating expenses		36,408			127,502			81,779			237,120
Lease operating expenses		14,390			25,621			41,291			44,959
General and administrative expenses		461,539			734,720			946,103			1,260,307
Depletion, depreciation and amortization		331,727			463,028			660,515			718,781
Abandonment expense		23,901			-			51,352			-
Accretion expense		31,177			29,189			56,340			50,750
Total cost of operations		109,495,503			91,671,203			219,501,611			139,307,037
Loss from operations		(5,105,630	)		(7,129,205	)		(5,867,083	)		(8,918,110	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		278,349			81,364			556,699			175,319
Interest and other income		977			2,265			1,812			3,915
Interest expense		(280,706	)		(275,333	)		(561,769	)		(508,850	)
Total other expense		(1,380	)		(191,704	)		(3,258	)		(329,616	)
Loss from continuing operations before income taxes		(5,107,010	)		(7,320,909	)		(5,870,341	)		(9,247,726	)
Tax expense
Current		-			17,419			-			(13,144	)
Deferred		-			-			-			-
Income tax (expense) benefit		-			17,419			-			(13,144	)
Loss from continuing operations, net of tax		(5,107,010	)		(7,303,490	)		(5,870,341	)		(9,260,870	)
Loss from discontinued operations, net of tax		-			(94,344	)		-			(106,858	)
Net loss	$	(5,107,010	)	$	(7,397,834	)	$	(5,870,341	)	$	(9,367,728	)
Basic loss per common share
Continuing operations	$	(0.49	)	$	(0.69	)	$	(0.56	)	$	(0.93	)
Discontinued operations	$	-		$	(0.01	)	$	-		$	(0.01	)
Basic loss per common share	$	(0.49	)	$	(0.70	)	$	(0.56	)	$	(0.94	)
Diluted loss per common share
Continuing operations	$	(0.49	)	$	(0.69	)	$	(0.56	)	$	(0.93	)
Discontinued operations	$	-		$	(0.01	)	$	-		$	(0.01	)
Diluted loss per common share	$	(0.49	)	$	(0.70	)	$	(0.56	)	$	(0.94	)
Weighted average number of common shares outstanding:
Basic		10,421,629			10,541,853			10,465,736			10,002,926
Diluted		10,421,629			10,541,853			10,465,736			10,002,926

See accompanying notes to condensed consolidated financial statements.

4

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
	2013			2012
OPERATING ACTIVITIES
Net loss	$	(5,870,341	)	$	(9,367,728	)
Loss from discontinued operations		-			106,858
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization		660,515			713,071
Unrealized loss (gain) on derivatives		(215,300	)		126,983
Amortization of debt issue costs		16,900			16,899
Amortization of intangible assets		9,463			5,710
Accretion expense		56,340			50,750
Abandonment costs incurred		51,352			(3,685	)
Common stock issued for services		50,000			119,000
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash		62,226			(538	)
Accounts receivable		6,416,559			(5,589,773	)
Prepaid expenses and other current assets		(36,072	)		24,272
Deposits		(4,213	)		(775,921	)
Inventory		(1,033,422	)		810,594
Accounts payable, accrued expenses and other liabilities		(4,233,122	)		8,736,277
Accounts payable, related party		913,401			2,022,546
Net cash used in operating activities - continuing operations		(3,155,714	)		(3,004,685	)
Net cash used in operating activities - discontinued operations		-			(12,577	)
Net cash used in operating activities		(3,155,714	)		(3,017,262	)
INVESTING ACTIVITIES
Capital expenditures		(887,970	)		(2,074,137	)
Proceeds from sale of assets		201,000			-
Cash acquired on acquisition		-			1,674,594
Net cash used in investing activities		(686,970	)		(399,543	)
FINANCING ACTIVITIES
Proceeds from issuance of debt		3,705,191			4,252,847
Payments on long-term debt		(60,876	)		(356,651	)
Proceeds from notes payable		15,032			16,000
Payments on notes payable		(56,740	)		(18,925	)
Net cash provided by financing activities		3,602,607			3,893,271
Net increase (decrease) in cash and cash equivalents		(240,077	)		476,466
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		420,896			1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	180,819		$	478,288
Supplemental Information:
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	$	800,000		$	-
Non-cash investing and financing activities:
Financing of insurance premiums	$	-		$	82,560
Related party payable converted to equity	$	-		$	993,732
Acquisition of Blue Dolphin at fair value, inclusive
of cash acquired of $1,674,594	$	-		$	18,046,154
Accrued services payable converted to common stock	$	50,000		$	119,000

See accompanying notes to condensed consolidated financial statements.

5

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

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

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

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

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

●   Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations);

●   Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);

●   Blue Dolphin Services Co., a Texas corporation (administrative services);

●   Blue Dolphin Exploration Company, a Delaware corporation (exploration and production investments) (“BDEX”); and

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

(2) Basis of Presentation

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

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

6

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(3) Significant Accounting Policies

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

Use of Estimates

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

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $180,819 and $420,896 at June 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,367 and $89,593 at June 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. We had uninsured balances of $0 and $170,896 at June 30, 2013 and December 31, 2012, respectively.

For the three months ended June 30, 2013, we had four customers that accounted for approximately 81% of our refined petroleum product sales. These four customers represented approximately $6.6 million in accounts receivable at June 30, 2013. For the six months ended June 30, 2013, we had five customers that accounted for approximately 91% of our refined petroleum product sales. These five customers represented approximately $7.5 million in accounts receivable at June 30, 2013.

For the three months ended June 30, 2012, we had three customers that accounted for approximately 79% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012. For the six months ended June 30, 2012, we had three customers that accounted for approximately 69% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012.

7

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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. Although such hedge positions are direct contractual obligations of Genesis and not us, we record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three and six months ended June 30, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three and six months ended June 30, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

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

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

8

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Intangibles – Goodwill and Other

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

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

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

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

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

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

9

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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 $515,435 and $532,335 at June 30, 2013 and December 31, 2012, respectively. Accumulated amortization was $160,545 and $143,645 at June 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note. For the three and six months ended June 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. For the three and six months ended June 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. See “Note (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

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

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

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

Income Taxes

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

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards. See “Note (20) Income Taxes” for further details.

10

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

11

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Treasury Stock

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

Business Combinations

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

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

12

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Reclassification

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

New Pronouncements Issued but Not Yet Effective

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

(4) Business Segment Information

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

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

	Three Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	104,312,768		$	77,105		$	-		$	-		$	104,389,873
Operation cost(2)		(108,600,407	)		(122,066	)		(42,395	)		(398,908	)		(109,163,776	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(4,009,290	)	$	(44,961	)	$	(42,395	)	$	(398,908	)
Depletion, depreciation and amortization														(331,727	)
Other income (expense), net														(279,729	)
Loss from continuing operations,
before income taxes													$	(5,107,010	)
Loss from discontinued operations													$	-
Capital expenditures	$	357,744		$	-		$	-		$	-		$	357,744
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $212,001 and an unrealized gain of $79,200.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

13

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

	Three Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	84,416,296		$	124,476		$	1,226		$	-		$	84,541,998
Operation cost(2)		(90,369,807	)		(241,503	)		(218,085	)		(378,780	)		(91,208,175	)
Other non-interest income		81,364			-			-			-			81,364
EBITDA	$	(5,872,147	)	$	(117,027	)	$	(216,859	)	$	(378,780	)
Depletion, depreciation and amortization														(463,028	)
Other income (expense), net														(273,068	)
Loss from continuing operations,
before income taxes													$	(7,320,909	)
Loss from discontinued operations													$	(94,344	)
Capital expenditures	$	724,805		$	-		$	-		$	-		$	724,805
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

__________________________

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue.
(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 six months ended June 30, 2013 (and at June 30, 2013) were as follows:

	Six Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	213,484,275		$	150,253		$	-		$	-		$	213,634,528
Operation cost(2)		(217,664,084	)		(218,901	)		(100,059	)		(858,052	)		(218,841,096	)
Other non-interest income		556,699			-			-			-			556,699
EBITDA	$	(3,623,110	)	$	(68,648	)	$	(100,059	)	$	(858,052	)
Depletion, depreciation and amortization														(660,515	)
Other income (expense), net														(559,957	)
Loss from continuing operations, before income taxes													$	(5,870,341	)
Loss from discontinued operations													$	-
Capital expenditures	$	887,970		$	-		$	-		$	-		$	887,970
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $248,441 and an unrealized gain of $215,300.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

15

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

	Six Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	130,187,259		$	194,386		$	7,282		$	-		$	130,388,927
Operation cost(2)		(137,232,245	)		(437,220	)		(422,372	)		(496,419	)		(138,588,256	)
Other non-interest income		175,319			-			-			-			175,319
EBITDA	$	267,594,823		$	631,606		$	429,654		$	496,419
Depletion, depreciation and amortization														(718,781	)
Other income (expense), net														(504,935	)
Loss from continuing operations, before income taxes													$	(9,247,726	)
Loss from discontinued operations													$	(106,858	)
Capital expenditures	$	2,074,137		$	-		$	-		$	-		$	2,074,137
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

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

16

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(5) Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at June 30, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at June 30, 2013 and December 31, 2012 was $19,453,025 and $15,850,418, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and the basis for that measurement:

			Fair Value Measurement at June 30, 2013 Using
Financial assets:	Carrying Value as at June 30, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	79,200	$	79,200	$	-	$	-

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

17

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

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

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

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 June 30, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

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

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

		Fair Value
		June 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$	79,200	$	(136,100	)

18

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

		Gain (Loss) Recognized
		Three Months Ended June 30,				Six Months Ended June 30,
Derivatives	Statements of Operations Location	2013		2012		2013			2012
Commodity contracts	Cost of refined products sold	$	55,350	$	-	$	(33,141	)	$	-

(7) Concentration of Risk

Key Supplier. GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis, 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 of our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products.

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

	Six Months Ended June 30,
	2013			2012
Low-sulfur diesel		49.8	%		45.6	%
Naphtha		26.3	%		26.8	%
Atmospheric gas oil		23.8	%		27.1	%
Reduced crude		0.1	%		0.5	%
		100.0	%		100.0	%

19

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(8) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	June 30,		December 31,
	2013		2012
Prepaid insurance	$	101,673	$	185,814
Prepaid restructuring fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		79,200		-
	$	264,386	$	228,314

(9) Deposits

Deposit balances consisted of the following:

	June 30,		December 31,
	2013		2012
Utility deposits	$	31,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,240,660	$	1,236,447

20

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(10) Inventories

Inventory balances consisted of the following:

	June 30,		December 31,
	2013		2012
Low-sulfur diesel	$	1,054,402	$	397,240
Naphtha		1,510,195		1,562,055
Atmospheric gas oil		750,476		322,356
Crude		19,041		19,041
	$	3,334,114	$	2,300,692

(11) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	June 30,		December 31,
	2013		2012
Refinery and facilities	$	34,734,307	$	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		443,939		577,567
		37,315,457		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,334,665		1,674,151
		34,980,792		35,040,826
Construction in Progress		907,748		821,259
Property, Plant and Equipment, Net	$	35,888,540	$	35,862,085

21

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(12) Discontinued Operations

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

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Revenue	$	-	$	248,855		$	-	$	443,139
Lease operating expenses		-		273,341			-		455,716
Depletion, depreciation and amortization		-		57,362			-		79,571
Accretion expense		-		12,496			-		14,710
Total costs and expenses		-		343,199			-		549,997
Loss from discontinued operations, net of tax	$	-	$	(94,344	)	$	-	$	(106,858	)

(13) Accounts Payable, Related Party

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

Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement 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 June 30, 2013 and 2012 were $2,724,644 (approximately $2.70 per barrel) and $2,239,914 (approximately $2.85 per barrel). Aggregate amounts expensed for Services at the Nixon Facility for the six months ended June 30, 2013 and 2012 were $5,469,853 (approximately $2.75 per barrel) and $3,302,665 (approximately $2.80 per barrel). At June 30, 2013 and December 31, 2012, the amounts outstanding to LEH were $2,507,422 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.

22

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(14) Notes Payable

Notes payable at June 30, 2013 and December 31, 2012 was $46,136 and $43,941, respectively.

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 $34,865 and $39,866 at June 30, 2013 and December 31, 2012, respectively. The unsecured note, which bears interest at a base rate of 10% and a default rate of 18%, was originally due in January 2012. The due date has been extended to December 2013. 

Short-Term Capital Leases. The balance on short-term notes under capital lease agreements was $11,271 and $0 at June 30, 2013 and December 31, 2012, respectively. In January 2013 we acquired a pressure washer under an interest-free, short-term capital lease. Capital leases totaling $1,250, which were classified as long-term debt at December 31, 2012, have been re-classified to short-term debt at June 30, 2013 as they mature at various dates through February 2014. These capital leases have interest rates ranging from 0% to 13.04%. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets. The assets are amortized over the lower of their related lease terms or their estimated productive lives.

The balance on a short-term note related to previously owned trucks for use at the Nixon Facility was $0 and $4,075 at June 30, 2013 and December 31, 2012, respectively. The unsecured note bore interest at 5%.

(15) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	June 30,		December 31,
	2013		2012
Excise taxes	$	283,640	$	292,303
Turnaround expenses		63,646		-
Transportation		-		69,551
Other payable		252,199		134,501
Property taxes		27,000		-
Insurance		22,440		-
Unrealized hedging loss		-		136,100
Unearned revenue		65,000		92,783
	$	713,925	$	725,238

23

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(16) Asset Retirement Obligations

Refinery and Facilities

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

Oil and Gas Properties and Pipelines and Facilities Assets

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

Asset retirment obligations at December 31, 2012	$	921,260
Liabilities settled		(8,244	)
Accretion expense		56,341
		969,357
Less:  current portion of asset retirement obligations		85,347
Asset retirement obligations, long-term balance
at June 30, 2013	$	884,010

For the three months ended June 30, 2013, we recognized $23,901 in abandonment expense for AROs associated with our High Island A-7 oil and gas property. Abandonment costs for High Island A-7, which exceeded the ARO liability, were recognized as a loss during the period. We will record additional plugging and abandonment costs for High Island A-7 as information becomes available from the operator, Apache Corp., to substantiate actual and/or probable costs.

24

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(17) Long-Term Debt

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

	June 30,		December 31,
	2013		2012
Refinery Note	$	9,256,114	$	9,298,183
Construction and Funding Agreement		8,850,775		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Captial Leases		-		2,119
		19,406,889		15,806,477
Less: Current portion of long-term debt		10,741,114		1,816,960
	$	8,665,775	$	13,989,517

Refinery Note. On September 29, 2008 LE entered into a loan agreement (the “Loan Agreement”) with First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000 (the “Refinery Note”). The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at June 30, 2013) and has a maturity date of October 1, 2028 (the “Maturity Date”). LE’s obligations under the Refinery Note are secured by a Deed of Trust (the “Deed of Trust”) of even date with the Loan Agreement. The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Loan Agreement, the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE. Previously, we were in default under our Refinery Loan Documents and, on August 12, 2011, the Loan Agreement and Refinery Note were subject to a forbearance agreement (the “Forbearance Agreement”). The principal balance outstanding on the Refinery Note was $9,256,114 and $9,298,183 at June 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Refinery Note in the amount of $38,181 and $250,070 at June 30, 2013 and December 31, 2012, respectively.

Pursuant to the Forbearance Agreement, FIB agreed to forbear further from exercising its rights and remedies under the Refinery Loan Documents in order to permit us to pay all arrearages and fees (the “Arrearages”). The Forbearance Agreement commenced on August 12, 2011 and expired on August 12, 2013. To date, all Arrearages have been fully paid. In addition, the Loan Agreement and the Refinery Note are no longer subject to the Forbearance Agreement, and the Refinery Loan Documents have been fully reinstated in accordance with the terms and conditions thereof. The Loan Agreement has various financial covenants relating to a current ratio and debt to net worth. If currently measured, we would be in violation of these covenants. We do not expect to cure these violations before the next measurement date, which is September 30, 2013. As a resault, the Refinery Note has been included in the current portion of long-term debt on the condensed consolidated balance sheet as of June 30, 2013.

In October 2011, the Refinery Loan Documents were acquired by American First National Bank (“AFNB”). On June 1, 2013, AFNB and LE amended the Refinery Note (the “Note Modification Agreement”). Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310. Other than modification of the payment terms under the Refinery Note, the terms under the Loan Agreement and the Refinery Note remain the same through the Maturity Date and the Refinery Loan Documents remain in full force and effect.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations. We started making payments under the Construction and Funding Agreement in the first quarter of 2012. All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually. The principal balance outstanding on the Construction and Funding Agreement was $8,850,775 and $5,206,175 at June 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $536,052 and $386,695 at June 30, 2013 and December 31, 2012, respectively. There are no financial covenants associated with this obligation.

See “Note (21) 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.

25

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Notre Dame Debt. LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8,000,000, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at a default rate of 16% and is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at June 30, 2013 and December 31, 2012. Interest was accrued on the Notre Dame Debt in the amount of $961,929 and $858,784 at June 30, 2013 and December 31, 2012, respectively. There are no financial covenants associated with the Notre Dame Debt.

Pursuant to an Intercreditor and Subordination Agreement dated September 29, 2008, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of the holder of the Refinery Note, the Deed of Trust and Security Agreement.

Pursuant to an Intercreditor and Subordination Agreement dated August 12, 2011, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of Milam under the Construction and Funding Agreement.

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

(18) Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month. The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. For the three months ended June 30, 2013 and 2012, rent expense for the office lease was $25,161 and $28,344, respectively. For the six months ended June 30, 2013 and 2012, rent expense for the office lease was $51,221 and $52,121, respectively.

(19) Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia. The non-cash transaction was completed on February 28, 2013. Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of common stock, which represented a recovery of a significant portion of the 342,857 shares of common stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock. As of June 30, 2013, there were 150,000 shares of treasury stock.

(20) Income Taxes

LE is a limited liability company and, prior to the Merger, its taxable income or net operating losses (“NOLs”) flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon the Merger, LE became the subsidiary of Blue Dolphin and LE’s taxable income or NOLs flowed through to Blue Dolphin for federal and state income tax purposes. However, Section 382 of the Internal Revenue Code imposes a limitation on Blue Dolphin’s use of LE’s NOLs. The amount of NOLs subject to such limitations is approximately $18.5 million. Nevertheless, the NOLs generated subsequent to the Merger, approximately $13.3 million, is not subject to any such limitation. For the three and six months ended June 30, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended June 30, 2013 and 2012, income tax expense was $0 and income tax benefit was $17,419, respectively. For the six months ended June 30, 2013 and 2012, income tax expense was $0 and $13,144, respectively. Income tax expense and benefit related to the State of Texas margins tax (“TMT”). TMT is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.

26

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(21) Commitments and Contingencies

Management Agreement

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

Genesis Agreements

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

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL, an affiliate of Genesis, is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. 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 Note 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.

27

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

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

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

(c)

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

(d)

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

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

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. 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.

28

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

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

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

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

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

As of June 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $8,850,775. As of June 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $5,395,050.

Refinery Note

As of June 30, 2013, the principal balance outstanding on the Refinery Note was $9,256,114. During the three months ended June 30, 2013, GEL paid AFNB in the amount of $178,646 to repay all Arrearages.

29

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

Lazarus Energy Development, LLC (“LED”) Option

In connection with the Merger, we purchased an exclusive option, which expires on 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.

30

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

(22) Earnings Per Share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Loss from continuing operations, net of tax	$	(5,107,010	)	$	(7,303,490	)	$	(5,870,341	)	$	(9,260,870	)
Loss from discontinued operations, net of tax		-			(94,344	)		-			(106,858	)
Net loss		(5,107,010	)		(7,397,834	)		(5,870,341	)		(9,367,728	)
Basic and diluted loss per common share
Continuing operations	$	(0.49	)	$	(0.69	)	$	(0.56	)	$	(0.93	)
Discontinued operations	$	-		$	(0.01	)	$	-		$	(0.01	)
Basic and diluted loss per common share	$	(0.49	)	$	(0.70	)	$	(0.56	)	$	(0.94	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,629			10,541,853			10,465,736			10,002,926

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 and six months ended June 30, 2013 and 2012 excludes stock options outstanding as they would be anti-dilutive.

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

(23) 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 approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

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

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

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at June 30, 2013		14,642	$	19.67		0.4	$	-
Options exercisable at June 30, 2013		14,642	$	19.67		0.4	$	-

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

For the three and six months ended June 30, 2013, we recognized $0 and $50,000 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered. For the three and six months ended June 30, 2012, we recognized $99,000 and $119,000 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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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”) and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013. In this document, the words “Blue Dolphin,” “we,” “us” and “our” refer to Blue Dolphin Energy Company and its subsidiaries.

Forward Looking Statements

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

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

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

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

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

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

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

● our 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;

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

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

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

● competition from larger companies;

● acquisition expenses and integration difficulties; and

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

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

Company Overview

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

Refinery Operations

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

We purchase crude oil and condensate for the Nixon Facility under an exclusive supply agreement with GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis, and have the ability to produce refined products such as Non-Road Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), kerosene, jet fuel and intermediate products, including liquefied petroleum gas, 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.

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Oil and Gas Exploration and Production

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

Key Operating Statistics

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Nixon Facility
Operating days		90			88			175			148
Total refinery throughput(1)
bbls		1,008,857			786,017			1,987,662			1,177,525
bpd		11,210			8,932			11,358			7,956
Capacity utilization rate		75	%		60	%		76	%		53	%
Total refinery production
bbls		984,922			776,377			1,943,228			1,160,530
bpd		10,944			8,822			11,104			7,841
Capacity utilization rate		73	%		59	%		74	%		52	%

(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.

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

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

Critical Accounting Policies and Estimates

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

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

Relationship with Genesis

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

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

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

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

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.

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

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(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 June 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $8,850,775. As of June 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $5,395,050.

Results of Operations

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

During the Prior Quarter, the Nixon Facility, which was refurbished and began operations in February 2012, operated for a total of 88 days at 60% of operating capacity. During the Current Quarter, the Nixon Facility operated for 90 days at 75% of operating capacity.

Current Quarter Compared to Prior Quarter

Summary. For the Current Quarter we reported a loss from continuing operations, net of tax, of $5,107,010, or a loss of $0.49 per share, compared to a loss from continuing operations, net of tax, of $7,303,490, or a loss of $0.69 per share, for the Prior Quarter. We reported a loss from discontinued operations of $94,344, or a loss of $0.01 per share, in the Prior Quarter compared to no loss from discontinued operations in the Current Quarter. The loss from continuing operations, net of tax, in the Current Quarter was primarily attributable to lower refining margins.

Total Revenue from Operations. For the Current Quarter we had total revenue from operations of $104,389,873 compared to total revenue from operations of $84,541,998 for the Prior Quarter. The increase in total revenue from operations was primarily the result of a 26% increase in refined product sales at the Nixon Facility. Substantially all of our revenue in the Current Quarter came from refined product sales, which generated revenue of $104,312,768, or more than 99% of total revenue from operations, compared to $84,416,296, or more than 99% of total revenue from operations, in the Prior Quarter.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $105,871,717 for the Current Quarter compared to $88,051,229 for the Prior Quarter. The increase in cost of refined products sold was primarily the result of a 26% increase in refined product sales at the Nixon Facility.

Refinery Operating Expenses. We recorded refinery operating expenses of $2,724,644 in the Current Quarter, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH. For the Prior Quarter, we recorded refinery operating expenses of $2,239,914. See “Part I, Item 1. Financial Statements - Note (13), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $36,408 in the Current Quarter compared to $127,502 in the Prior Quarter. The decline in pipeline operating expenses was the result of lower throughput on our pipeline systems.

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Lease Operating Expenses. Lease operating expenses totaled $14,390 in the Current Quarter compared to $25,621 in the Prior Quarter. The decline in lease operating expenses was due to leases being relinquished and fields being shut-in by operators.

General and Administrative Expenses. General and administrative expenses decreased from $734,720 in the Prior Quarter to $461,539 in the quarter. The decrease in general and administrative expenses in the Current Quarter was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization decreased from $463,028 in the Prior Quarter to $331,727 in the Current Quarter. We recorded a significant impairment to our pipeline and oil and gas assets in 2012, which reduced the carrying value of these assets and resulted in a corresponding decrease in depletion, depreciation and amortization expense.

Abandonment Expense. We recognized $23,901 of abandonment expense in the Current Quarter related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. Abandonment costs for High Island A-7, which exceeded the asset retirement obligation liability, were recognized as a loss during the period. There was no comparable expense in the Prior Quarter.

Other Income. We recognized $278,349 in net tank rental revenue in the Current Quarter compared to $81,364 in the Prior Quarter. The increase in net tank rental revenue was primarily a result of additional tanks being leased.

Discontinued Operations, Net of Tax. We reported a loss from discontinued operations, net of tax, of $94,344 in the Prior Quarter compared to $0 in the Current Quarter.

Six Months Ended June 30, 2013 (the “Current Six Months”) Compared to Six Months Ended June 30, 2012 (the “Prior Six Months”)

During the Prior Six Months, the Nixon Facility, which was refurbished and began operations in February 2012, operated for a total of 148 days at 53% of operating capacity. During the Current Six Months, the Nixon Facility operated for 175 days at 76% of operating capacity.

Current Six Months Compared to Prior Six Months

Summary. For the Current Six Months we reported a loss from continuing operations, net of tax, of $5,870,341, or a loss of $0.56 per share, compared to a loss from continuing operations, net of tax, of $9,260,870, or a loss of $0.93 per share, for the Prior Six Months. We reported a loss from discontinued operations of $106,858, or a loss of $0.01 per share, in the Prior Six Months compared to no loss from discontinued operations in the Current Six Months. The loss from continuing operations, net of tax, in the Current Six Months was primarily attributable to lower refining margins combined with lost sales as a result of a planned maintenance turnaround during the first quarter of 2013. During the Current Six Months, we adopted a condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, such as installation of new laboratory equipment and a new caustic system, to enhance profitability of our existing assets.

Total Revenue from Operations. For the Current Six Months we had total revenue from operations of $213,634,528 compared to total revenue from operations of $130,388,927 for the Prior Six Months. The increase in total revenue from operations was primarily the result of a 66% increase in refined products sales at the Nixon Facility. Substantially all of our revenue in the Current Six Months came from refined product sales, which generated revenue of $213,484,275, or more than 99% of total revenue from operations, compared to $130,187,259, or more than 99% of total revenue from operations, in the Prior Six Months.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $212,194,378 for the Current Six Months compared to $133,692,455 for the Prior Six Months. The increase in cost of refined products sold was the result of the Nixon Facility operating for 27 more days in the period and a 66% increase in refined product sales.

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Refinery Operating Expenses. We recorded refinery operating expenses of $5,469,853 in the Current Six Months, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH. For the Prior Six Months, we recorded refinery operating expenses of $3,302,665. See “Part I, Item 1. Financial Statements - Note (13), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $81,779 in the Current Six Months compared to $237,120 in the Prior Months. The decline in pipeline operating expenses was the result of lower throughput on our pipeline systems.

Lease Operating Expenses. Lease operating expenses totaled $41,291 in the Current Six Months compared to $44,959 in the Prior Months.

General and Administrative Expenses. General and administrative expenses decreased from $1,260,307 in the Prior Months to $946,103 in the Current Six Months. The decrease in general and administrative expenses in the Current Six Months was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization decreased from $718,781 in the Prior Six Months to $660,515 in the Current Six Months. We recorded a significant impairment to our pipeline and oil and gas assets in 2012, which reduced the carrying value of these assets and resulted in a corresponding decrease in depletion, depreciation and amortization expense.

Abandonment Expense. We recognized $51,352 of abandonment expense in the Current Six Months related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. Abandonment costs for High Island A-7, which exceeded the asset retirement obligation liability, were recognized as a loss during the period. There was no comparable expense in the Prior Six Months.

Other Income. We recognized $556,699 in net tank rental revenue in the Current Six Months compared to $175,319 in the Prior Six Months. The increase in net tank rental revenue was primarily a result of additional tanks being leased.

Discontinued Operations, Net of Tax. We reported a loss from discontinued operations, net of tax, of $106,858 in the Prior Six Months compared to $0 in the Current Six Months.

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

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

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

	Three Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	104,312,768		$	77,105		$	-		$	-		$	104,389,873
Operation cost(2)		(108,600,407	)		(122,066	)		(42,395	)		(398,908	)		(109,163,776	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(4,009,290	)	$	(44,961	)	$	(42,395	)	$	(398,908	)	$	(4,495,554	)
Depletion, depreciation and amortization														(331,727	)
Other income (expense), net														(279,729	)
Loss from continuing operations,
before income taxes													$	(5,107,010	)
Loss from discontinued operations													$	-
Capital expenditures	$	357,744		$	-		$	-		$	-		$	357,744
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $212,001 and an unrealized gain of $79,200.
(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 June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	84,416,296		$	124,476		$	1,226		$	-		$	84,541,998
Operation cost(2)		(90,369,807	)		(241,503	)		(218,085	)		(378,780	)		(91,208,175	)
Other non-interest income		81,364			-			-			-			81,364
EBITDA	$	(5,872,147	)	$	(117,027	)	$	(216,859	)	$	(378,780	)	$	(6,584,813	)
Depletion, depreciation and amortization														(463,028	)
Other income (expense), net														(273,068	)
Loss from continuing operations,
before income taxes													$	(7,320,909	)
Loss from discontinued operations													$	(94,344	)
Capital expenditures	$	724,805		$	-		$	-		$	-		$	724,805
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

__________________________

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

43

Blue Dolphin Energy Company & Subsidiaries

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

	Six Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	213,484,275		$	150,253		$	-		$	-		$	213,634,528
Operation cost(2)		(217,664,084	)		(218,901	)		(100,059	)		(858,052	)		(218,841,096	)
Other non-interest income		556,699			-			-			-			556,699
EBITDA	$	(3,623,110	)	$	(68,648	)	$	(100,059	)	$	(858,052	)	$	(4,649,869	)
Depletion, depreciation and amortization														(660,515	)
Other income (expense), net														(559,957	)
Loss from continuing operations,
before income taxes													$	(5,870,341	)
Loss from discontinued operations													$	-
Capital expenditures	$	887,970		$	-		$	-		$	-		$	887,970
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $248,441 and an unrealized gain of $215,300.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

44

Blue Dolphin Energy Company & Subsidiaries

	Six Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	130,187,259		$	194,386		$	7,282		$	-		$	130,388,927
Operation cost(2)		(137,232,245	)		(437,220	)		(422,372	)		(496,419	)		(138,588,256	)
Other non-interest income		175,319			-			-			-			175,319
EBITDA	$	267,594,823		$	631,606		$	429,654		$	496,419		$	(8,024,010	)
Depletion, depreciation and amortization														(718,781	)
Other income (expense), net														(504,935	)
Loss from continuing operations,
before income taxes													$	(9,247,726	)
Loss from discontinued operations													$	(106,858	)
Capital expenditures	$	2,074,137		$	-		$	-		$	-		$	2,074,137
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

__________________________

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

45

Blue Dolphin Energy Company & Subsidiaries

Liquidity and Capital Resources

Sources and Uses of Cash. At June 30, 2013, our available cash was $180,819. 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. During 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.

	For Three Months Ended June 30,						For Six Months Ended June 30,
	2013			2012			2013			2012
Cash flow from operations
Adjusted loss from continuing operations	$	(4,979,105	)	$	(6,580,415	)	$	(5,241,071	)	$	(8,232,142	)
Adjusted loss from discontinued operations		-			(24,486	)					(12,577	)
Change in assets and current liabilities		1,569,686			5,165,998			2,085,357			5,227,457
Total cash flow from operations		(3,409,419	)		(1,438,903	)		(3,155,714	)		(3,017,262	)
Cash inflows (outflows)
Proceeds from issuance of debt		3,705,191			1,888,835			3,705,191			4,252,847
Payments on long term debt		-			(353,735	)		(60,876	)		(356,651	)
Cash acquired on Acquisition		-			-			-			1,674,594
Capital expenditures		(357,744	)		(724,805	)		(887,970	)		(2,074,137	)
Proceeds from sale of assets		201,000			-			201,000			-
Proceeds from notes payable		-			16,000			15,032			16,000
Payments on note payble		(46,268	)		(18,925	)		(56,740	)		(18,925	)
Total cash inflows (outflows)		3,502,179			807,370			2,915,637			3,493,728
Total change in cash flows	$	92,760		$	(631,533	)	$	(240,077	)	$	476,466

We are currently relying on our profit share, GEL and LEH to fund our working capital requirements. During months in which we receive no profit share distribution, GEL and/or LEH may, but are not required to, fund our operating losses. As of June 30, 2013, the Deficit Amount financed by GEL was $5,395,050 and the working capital amount funded by LEH was $2,507,422. 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 working capital requirements. In the event our working capital requirements are not funded by our profit share, GEL or LEH, we may experience a significant and material adverse effect on our operations, liquidity and financial condition. See “Item 1A. Risk Factors” in our Annual Report” and “Part I, Item 1A. Risk Factors” in this report for risk factors related to our working capital needs.

46

Blue Dolphin Energy Company & Subsidiaries

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 negative cash flow from operations of $3,409,419. For the Prior Quarter, we experienced negative cash flow from operations of $1,438,903. This represents a decline in cash flow from operations of $1,970,516 for the Current Quarter compared to the Prior Quarter.

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.

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

We recognized $23,901 and $51,352 of abandonment expense in the Current Quarter and Current Six Months, respectively, related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount for High Island A-7, which exceeded the asset retirement obligation liability, was recognized as a loss during the respective periods. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

Capital expenditures in the Current Quarter and Current Six Months totaled $156,744 and $686,970, respectively, and consisted of $357,744 and $887,970, respectively, related to investments in the Nixon Facility. We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $8,850,775 and $5,206,175, including Deficit Amounts, at June 30, 2013 and December 31, 2012, respectively.

The principal balance outstanding on the Refinery Note was $9,256,114 and $9,298,183 at June 30, 2013 and December 31, 2012, respectively. On June 1, 2013, AFNB and LE agreed to amend the Refinery Note (the “Note Modification Agreement”). Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310.

The principal balance outstanding on the Notre Dame Debt, which is currently in default, was $1,300,000 at June 30, 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 (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to our debt obligations.

47

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 June 30, 2103, we had $9,256,114 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 June 30, 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 June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

48

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 and Form 10-Q for the three months ended March 31, 2013. These risks and uncertainties could materially and adversely affect our business, financial condition and results of operations. Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business. 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 and the Form 10-Q for the three months ended March 31, 2013.

Genesis and LEH may, but are not required to, fund our working capital requirements.

Historically, we have used a portion of our cash reserves and revenue from operations to fund our working capital requirements. To the extent that we are unable to fund our working capital requirements from cash reserves and revenue from operations, we have relied on Genesis and LEH for our working capital requirements. As of June 30, 2013, the Deficit Amount financed by Genesis was $5,395,050 and the capital amount funded by LEH was $2,507,422. In the event our working capital requirements are not funded by Genesis or LEH, or we are otherwise unable to secure sufficient liquidity to support our short term and/or long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which may have a material adverse effect on our results of operations or liquidity.

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

None.

ITEM 3 DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

49

Blue Dolphin Energy Company & Subsidiaries

ITEM 6.EXHIBITS

(a) Exhibits: The following exhibits are filed herewith:

10.1	Note Modification Agreement effective June 1, 2013 by and between Lazarus Energy, LLC, Jonathan P. Carroll, Gina L. Carroll, Lazarus Energy Holdings, LLC, GEL TEX Marketing, LLC, Milam Services, Inc. and American First National Bank.
10.2	Letter from American First National Bank to Lazarus Energy, LLC dated as of December 13, 2012.
10.3	Letter from American First National Bank to Lazarus Energy, LLC dated as of July 24, 2013.
31.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.CA	XBRL Calculation Linkbase Document.
101.LAB	XBRL Label Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

50

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

51

EX-10.1

Exhibit 10.1

NOTE MODIFICATION AGREEMENT

This Note Modification Agreement (the "Agreement") is made and entered into effective as of June 1, 2013 (the "Effective Date") by and between LAZARUS ENERGY, LLC, a Delaware limited liability company (the "Borrower"), whose mailing address is 801 Travis, Suite 2100 Houston, Texas 77002, JONATHAN P. CARROLL ("Jonathan Carroll"), whose mailing address is801 Travis, Ste 2100 Houston, TX, GINA L. CARROLL ("Gina Carroll"), whose mailing address is 801 Travis, Ste 2100 Houston, TX, LAZARUS ENERGY HOLDINGS, LLC, a Delaware limited liability company ("LEH"), whose mailing address is 801 Travis, Ste 2100, Houston, TX 77002, GEL TEX MARKETING, LLC, a Delaware limited liability company ("GEL"), whose mailing address is 919 Milam, Ste 2100, Houston, TX 77002, MILAM SERVICES, INC., a Delaware corporation "Milam"), whose mailing address is 919 Milam, Ste 2100, Houston, TX 77002 and AMERICAN FIRST NATIONAL BANK, a national banking association (the "Lender"), whose mailing address is 9999 Bellaire Blvd., Houston, Harris County, Texas 77036, as follows:

WITNESSETH:

WHEREAS, the Borrower is indebted to the Lender as evidenced by that one (1) certain Promissory Note (the "Note") dated as of September 29, 2008, in the original principal amount of TEN MILLION AND 00/100 DOLLARS ($10,000,000.00) payable to the order of FIRST INTERNATIONAL BANK ("FIB"); and

WHEREAS, the Note is secured by, among other instruments, a Deed of Trust (with Security Agreement and Assignment of Rents) (the "Deed of Trust") of even date with the Note, executed by the Borrower, as mortgagor, to W.R,. KERR, TRUSTEE, for the use and benefit of the Lender, duly filed for record under Document No. 00038523 and in Volume 1479, Pages 196 et seq. in the Official Public Records of Real Property of Wilson County, Texas, which Deed of Trust covers the following described real property, to-wit:

See Exhibit "A", which is attached hereto and incorporated herein by reference for all purposes

and

WHEREAS, the Note is further secured by, among other instruments, a Security Agreement (the "Security Agreement") of even date with the Note, executed by the Borrower, as debtor, in favor of FIB, as secured party, which Security Agreement covers various items of collateral, as described in and covered by one (1) or more Financing Statements, duly filed in the Uniform Commercial Code Records of the states of Delaware and Texas, as appropriate; and

WHEREAS, the Note and other indebtedness of the Borrower are personally guaranteed by JONATHAN CARROLL, also sometimes known as JONATHAN PITTS CARROLL, SR., GINA CARROLL and LEH (collectively, a "Guarantor", whether one (1) or more, and the Note and the loan evidenced thereby (the "Loan") are subject to the terms of a Loan Agreement (the "Loan Agreement") of even date with the Note by and between the Borrower, each Guarantor and FIB; and

1

WHEREAS, the Deed of Trust, the Security Agreement, the Loan Agreement, each of the Guarantor's respective guarantees described above, and any other assignments, security agreements, financing statements, loan agreements or guaranty agreements relating to the Note are hereinafter collectively referred to as "Security Instruments", all liens, security interests and assignments securing the Note (including, without limitation, the Deed of Trust), are hereinafter collectively referred to as "Liens", and any terms defined in the Note and not redefined in this Agreement shall have the same meanings herein as therein; and

WHEREAS, the Note and the Loan are subject to a Forbearance Agreement (the "Forbearance Agreement") dated effective as of August 12, 2011 by and between FIB, the Borrower, each Guarantor, GEL and Milam, which Forbearance Agreement concerned certain defaults by the Borrower under the terms of the Loan, forbearance periods and various other matters; and

WHEREAS, on September 30, 2011, FIB was closed by banking regulators, the FEDERAL DEPOSIT INSURANCE CORPORATION ("FDIC") was appointed its receiver, and as Receiver of FIB, the FDIC sold the Loan, the Note, the Security Instruments and the Liens, together with all rights thereunder and thereto, to the Lender; and

WHEREAS, the Forbearance Agreement provided for two (2) forbearance periods, the first period (the "First Forbearance Period") commencing on the date of the Forbearance Agreement and ending August 12, 2012, and the second period (the "Second Forbearance Period") commencing August 12, 2012 and ending August 12, 2013, with the continuation of forbearance during the Second Forbearance Period being dependent whether certain conditions were met by the end of the First Forbearance Period; and

WHEREAS, the Borrower now desires to modify the Note, ratify the Liens and confirm that they continue to secure the Note, as modified hereby, and confirm that conditions permitting the Second Forbearance Period to commence have been met, and the Lender, the legal owner and holder of the Note and the Liens, in consideration of the premises and at the request of the Borrower, has agreed to modify the Note and confirm that the conditions required for the Second Forbearance Period have been met; and

WHEREAS, the parties acknowledge that the U.S. DEPARTMENT OF AGRICULTURE ("USDA") owns a portion of the Loan, the Note, the Security Instruments, the rights thereunder, and the Liens, and that approval by the USDA is required before this Agreement is effective; and

WHEREAS, approval of the matters covered hereby has been obtained from the USDA:

NOW, THEREFORE, in consideration of the premises, the Borrower, each Guarantor, GEL, Milam and the Lender agree as follows:

1.EXTENSION OF FORBEARANCE PERIOD. The Borrower and each Guarantor

represent and warrant that all conditions set forth in the Forbearance Agreement which are necessary for the Borrower to attain in order to qualify for the Second Forbearance Period have been met. GEL and Milam acknowledge that the Services (as contemplated by the Construction Agreement) have been completed under the Construction Contract (as defined in the Forbearance Agreement). The Lender

2

confirms that the conditions set forth in the Forbearance Agreement which are necessary for the Borrower to attain in order to qualify for the Second Forbearance Period have been met, and subject to any other provision of the Forbearance Agreement providing for its earlier termination, the Second Forbearance Agreement is extended to August 12, 2013.

2.          NOTE MODIFICATION(S). As of the Effective Date, the outstanding principal balance

of the Note is NINE MILLION TWO HUNDRED NINETY-EIGHT THOUSAND ONE HUNDRED EIGHTY-THREE AND 18/100 DOLLARS ($9,298,183.18). No further sums remain to be advanced under the Note. The following amendments are made to the Note:

(a)Beginning one (1) month after the Effective Date, the Note shall be payable in monthly installments of principal including interest, all of such installments, except for the last, being in the amount of SEVENTY-FIVE THOUSAND THREE HUNDRED TEN AND 35/100 DOLLARS ($75,310.35) each (or such greater amounts as may be required on account of the adjustment of the interest rate as provided for herein), the first such installment being due and payable one (1) month after the Effective Date, and each subsequent installment shall be due and payable on the same day of each succeeding calendar month thereafter until October 1, 2028, when the then remaining unpaid balance of principal of this Note, plus accrued interest, shall mature and finally become due and payable.

(b)Beginning on the Effective Date, the Note shall bear interest, except on past due sums, at a per annum rate equal to the lesser of either (i) the Prime Rate (as defined in the Note) plus TWO AND 25/100 PERCENT (2.25%), floating (which, if based on the Prime Rate in effect on the Effective Date, would result in a per annum interest rate of FIVE AND 50/100 PERCENT (5.50%)), or (ii) the Maximum Rate (as hereinafter defined) permitted by applicable law. All sums which become past due after the Effective Date shall bear interest as provided for in the Note for past due sums.

(c)The installments of principal and interest applicable to the Note, as modified hereby, have been calculated based on amortization of principal over a period of one hundred eighty-four (184) months and an interest rate of FIVE AND 50/100 PERCENT (5.50%) per annum. If the interest rate on the Note, as modified hereby, at any time after the effective date hereof exceeds FIVE AND 50/100 PERCENT (5.50%) per annum, the Borrower agrees that the Lender may recalculate the amount of the installment payments due under the Note, as modified hereby, to be sufficient to amortize the then outstanding principal balance of the Note, as modified hereby, over the remainder of its original period of amortization at the new interest rate, as provided for in the Note.

(d)After the Effective Date, if the Lender has not received the full amount of any installment payment due under the Note, as modified hereby, the Borrower understands that the Lender may impose, and if imposed, the Borrower shall pay to the Lender, a late charge in an amount and at such time as is provided for in the Note. These provisions shall not waive, modify or extend payment due dates or the Borrower's obligations to timely pay all installments due under the Note, as modified hereby.

(e)After the Effective Date, the Borrower agrees and understands that the pre-payment provisions contained in the Note shall remain in effect.

3.          USURY SAVINGS CLAUSE. It is the intention of the parties hereto to strictly comply

with and conform to all applicable law, including usury laws. Accordingly, notwithstanding any

3

provision of the Note, as modified hereby, any of the Security Instruments, any other document, instrument or agreement evidencing, securing or entered into in connection with the Note, as modified hereby, or the loan transaction evidenced thereby, it is expressly stipulated and agreed as follows:

(a)in no event shall the Borrower or any other liable party be required to pay interest in excess of the maximum non-usurious contract rate of interest (determined from time to time if the applicable maximum rate is a floating rate) that the Lender may charge the Borrower under applicable law and in regard to which the Borrower would be prevented successfully from raising the claim or defense of usury (the "Maximum Rate"), nor under any circumstances shall the aggregate of all consideration which constitutes interest under applicable law and taken, reserved, charged, received, contracted for, chargeable or receivable under the Note, as modified hereby, any of the Security Instruments, any other document, instrument or agreement evidencing, securing or entered into in connection with the Note, as modified hereby, or the loan transaction evidenced thereby, exceed the maximum amount of interest allowed by applicable law, and any excess interest shall be deemed a mistake and canceled automatically or, if theretofore paid, shall, at the option of the holder of the Note, as modified hereby, either be refunded to the Borrower or credited on the Note, as modified hereby, or any other obligation of the Borrower or any other liable party to the holder hereof; and

(b)in the event the maturity of the Note, as modified hereby, is accelerated for any reason before the due date thereof, or in the event of any prepayment hereof, then such consideration that constitutes interest under applicable law may never include or exceed more than the maximum amount allowed by applicable law, and excess interest, if any, provided for in the Note, as modified hereby, or otherwise shall be canceled automatically as of the date of such acceleration or prepayment, and, if theretofore paid, shall, at the option of the holder of the Note, as modified hereby, either be refunded to the Borrower or credited on the Note, as modified hereby, or any other obligation of the Borrower or any other liable party to the holder hereof.

In determining whether or not interest paid or payable exceeds the Maximum Rate, Lender and Borrower shall, to the extent permitted by applicable law, (a) characterize any non-principal payment as an expense, fee, or premium rather than as interest, (b) exclude voluntary prepayments and the effects thereof, and (c) amortize, prorate, allocate, and spread in equal or unequal parts the total amount of interest throughout the contemplated term of the indebtedness evidenced by the Note, as modified hereby, so that interest for the entire term does not exceed the Maximum Rate. The term "applicable law" shall mean the weekly ceiling from time to time in effect, as provided for in Chapter 303.002 of the Texas Finance Code, as amended, and also includes such other laws of the State of Texas and the United States, as such laws now exist or may be amended or changed in the future, or any new law enacted which is applicable to the Note, as modified hereby, or similar loans, whichever allows the greater rate of interest, provided however, it is expressly agreed that Chapter 346 of the Texas Finance Code, as amended (which regulates certain revolving credit accounts), shall not apply to this Note, as modified hereby, and the loan transaction contemplated thereby. The term "other liable party" includes, but is not limited to, the Borrower and each Guarantor.

4.           LIEN CONTINUATION AND OTHER PROVISIONS. The Liens are hereby ratified

and confirmed as continuing to secure payment of the Note, as modified hereby. Nothing herein shall in any manner diminish, impair or extinguish the Note, as modified hereby, any of the Security

4

Instruments, the Forbearance Agreement or the Liens securing the Note, as modified hereby. The Liens are not waived. To the extent of any conflict between the Note, as modified hereby, or the Forbearance Agreement, on the one hand, and this Agreement, on the other hand, this Agreement shall control. Except as hereby expressly modified, all terms of the Note, the Forbearance Agreement and the Security Instruments remain in full force and effect. This Agreement (a) shall bind and benefit the Borrower, each Guarantor, GEL, Milam, the Lender and their respective heirs, beneficiaries, administrators, executors, receivers, trustees, successors and assigns; (b) may be modified or amended only by a writing signed by each party; (c) shall be governed by the laws of the State of Texas and, to the extent applicable, the laws of the United States of America; (d) may be executed in several counterparts, and each original agreement shall be enforceable against all who signed it without production of or accounting for any other counterpart, and all separate counterparts shall constitute the same agreement; and (e) embodies the entire agreement and understanding between the parties with respect to the modification of instruments provided for herein and supersedes all prior conflicting or inconsistent agreements, consents and understandings relating to such subject matter. Any exhibits, appendices and annexes described in this Agreement as being attached to it are hereby incorporated into it. The headings in this Agreement shall be accorded no significance in interpreting it.

5.           RELEASE. The Borrower and each Guarantor acknowledge that there are no existing claims or defenses, personal or otherwise, or rights of setoff whatsoever with respect to the Note, any of the Security Instruments, or any other document, agreement or instrument executed or delivered in connection with, to evidence or as security for the Note. The Borrower and each Guarantor, for each of themselves and on behalf of their respective heirs, executors, predecessors, successors, assigns, officers, directors, employees, agents and servants (collectively, the "Releasing Parties") releases, acquits, and forever discharges the Lender, its predecessors, successors, assigns, officers, directors, employees, agents and servants, and all persons, natural or corporate, in privity with them or any of them, from any and all claims or causes of action of any kind whatsoever, at common law, statutory or otherwise, which the Releasing Parties, or any of them, has now or might have in the future, known or unknown, now existing or which might arise hereafter based on facts and events occurring through the date hereof, directly or indirectly attributable to the Note, any of the Security Instruments, or any other document, agreement or instrument executed or delivered in connection with, to evidence or as security for the Note, it being intended that this Agreement shall release all claims of any kind or nature that any of the Releasing Parties might have against those hereby released whether asserted or not.

6.           USDA APPROVAL LETTER. A copy of the USDA's approval letter dated December 12, 2012 (the "Letter") concerning matters set forth herein is attached as Exhibit "B" and is incorporated herein by reference. To the extent of any conflict between the Letter, on one hand, and this Agreement, the Note, any Security Instrument or the Forbearance Agreement, on the other hand, this Letter shall control, except the end of the Second Forbearande Period is not extended beyond August 13, 2013.

7.           JOINDER OF GEL AND MILAM. The parties acknowledge and agree that GEL and Milam are parties to this Agreement for the sole and limited purposes of delivering the acknowledgment in the second sentence of Section 1 of this Agreement and agreeing to the terms of Sections 4, 5 and 6 of this Agreement.

5

This written loan agreement represents the final agreement between the parties, and may not be contradicted by evidence of prior, contemporaneous, or subsequent oral agreements of the parties. There are no unwritten oral agreements between the parties relating to this Loan.

This Agreement has been executed on the dates of the acknowledgment of the respective parties as shown below, but is effective as of the Effective Date.

BORROWER:
LAZARUS ENERGY, LLC
By:	/s/ JONATHAN P. CARROLL
Printed Name:	Jonathan Carroll
Title:	Director
GUARANTOR:
	/s/ JONATHAN P. CARROLL
	JONATHAN P. CARROLL, Individually
	/s/ GINA L. CARROLL
	GINA L. CARROLL, Individually
LAZARUS ENERGY HOLDINGS, LLC
By:	/s/ JONATHAN P. CARROLL
Printed Name:	Jonathan Carroll
Title:	Director

6

	LENDER:
	AMERICAN FIRST NATIONAL BANK
	By:	/s/ ANALIZA DEL VALLE
	Printed Name:	Analiza Del Valle
	Title:	SVP
	OTHER PARTIES:
	GEL TEX MARKETING, LLC
	By:	/s/ R.V. DEERE
	Printed Name:	R.V. Deere
	Title:	CFO
	MILAM SERVICES, INC.
	By:	/s/ R.V. DEERE
	Printed Name:	R.V. Deere
	Title:	CFO
THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 2nd, 2013 by Jonathan P. Carroll, the Director of LAZARUS ENERGY, LLC, a Delaware limited liability company, on behalf of said company.
( Notary Seal)
		/s/ JENNIFER M. HARVEY
		Notary Public, State of Texas

7

THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 2nd, 2013 by JONATHAN P. CARROLL.
( Notary Seal)
	/s/ JENNIFER M. HARVEY
	Notary Public, State of Texas
THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 2nd, 2013 by GINA L. CARROLL.
( Notary Seal)
	/s/ JENNIFER M. HARVEY
	Notary Public, State of Texas
THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 2nd, 2013 by Jonathan P. Carroll, the Director of LAZARUS ENERGY HOLDINGS, LLC, a Delaware limited liability company, on behalf of said company.
( Notary Seal)
	/s/ JENNIFER M. HARVEY
	Notary Public, State of Texas

8

THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 3rd, 2013 by ANALIZA VALLE, the S.V.P. of AMERICAN FIRST NATIONAL BANK, a national banking association, on behalf of said national banking association.
( Notary Seal)
	/s/ QUYEN LE TRAN
	Notary Public, State of Texas
THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 1st, 2013 by R.V. DEERE, the CFO of GEL TEX MARKETING, LLC, a Delaware limited liability company, on behalf of said company.
( Notary Seal)
	/s/ JANEL R. WHITE
	Notary Public, State of Texas
THE STATE OF TEXAS                                           §
COUNTY OF Harris
This instrument was acknowledged before me on May 1st, 2013 by Jonathan P. Carroll, the R.V. DEERE, the CFO of MILAM SERVICES, INC., a Delaware corporation, on behalf of said corporation.
( Notary Seal)
	/s/ JANEL R. WHITE
	Notary Public, State of Texas

9

Doc                  Bk            V I            Pg

800147E6 DP                             I 34Z 702

BETTERSWORTII & ASSOCIATES, INC.

ENGINEERS - SURVEYORS - CONSULTANT'S EAST

MOUNTAIN STREET, SEGUIN, TEXAS 78155

22780'                                        MO) 379.5552 FAX (83o) 379.5553

754.51                                        &Midi! kaigiatteraworthassac.com

727804)-W

Mara 2, 20D6                                        larra L REINENOER, P.E.

66.309 ACRE TRACT

Being a 68.309 ACRE TRACT situated George McPeters Survey, A-419, Wilson County, Texas. Said 56.308 ACRE' TRACT is that tract conveyed by Bill Klingemann, Substitute Trustee, to Notre Dame Investors, Inc, by Substitute Trustee's Deed, in Volume 1159 et Page 609, dated May 06, 2003 and is comprised of all the tract- called 51.30 acres in conveyance from Leal Petroleum Corporation to American Petro Chemical Corporation recorded in Volume 842 at Page 705 and all of a tract called 5,000 acres in conveyance from Notre Dame Refining Corporation to American Petro Chemical 'Corporation recorded in Volume 1049 at Page 551 of the. Official Records of said county and being described by metes and bounds as follows:

BEGINNING at a one-half Inch diameter rebar set with cap (B&A) marking the northwest corner of the tract herein described, same being the northwest corner of said 51.30 acre tract, northeast corner of a tract called Tract 2-B (41.246 acres) in Volume 685 at Page 101, lying' in the south line of a tract called 7.654 acres in Volume 271 at Page 30, further described as lying in the south line of U.S. Highway No. 87; said point bears N 76° 16' 00' E. 1495.62 feet from a concrete right of way marker found;

THENCE with a segment of the north fine of the tract herein described, same being a segment of the common line of said 51.30 acre tract and said 7.654 acre tract, along a segrrient of the south line of U.S. Highway 87, N 76° 16' 00" E, 140.71 feet (called N 76° 16' E, 140.0 feet — bads of bearing) to a one-half inch diameter rebar set with cap (EISA) marking a north corner of the tract herein described, same being the north corner of said 51.30 acre tract, northwest corner residue celled 640 acres in Volume X at Page 136;

THENCE continuing with the north line of the tract herein described, same being the common line of said 51.30 acre tract with that of said residue 640 acre tract and a tract called 1.666 acres In Volume 1030 at Page 772 as follows:

S 13° 27' 49" E. 208.63 feet (called S 13° 37' E, 207.4 feet) to a five-eighths inch diameter rebar found near a two way fence corner,

N 76° 28' 34" E, 368.79 feet (called N 76° 29' E, 368.4 feet) to a one-half inch diameter rebar set with cap (B&A),

N 76° 28' 28' E, 31.40 feet (called N 76° 49' E, 31.4 feet) to a five-eighths inch diameter mbar found near a two way fence corner,

S 13° 55' 25" E, 238.17 feet (called S 140 00' E, 238.0 feet) to a five-eighths inch diameter rebar found marking a re-entrant corner of the tract herein described, same being the southwest corner of said residue 640 acre tract,

N 76° 06' 05" E, at 388.77 feet a one Inch diameter iron pipe found and at, 38862, (N 76° 16' E, 388.1 feet) to a one-half inch diameter rebar set with cap (B&A) marking a re-entrant corner of he tract herein described, same being the southeast corner of said residue 640 acre tract and

N 13° 36' 45" W, at 1.84 feet a one Inch diameter iron pipe found and at 446.92 feet (called N 13° 37' W, 447.1 feet) to a one-half Inch diameter rebar found marking a north corner •of the tract herein described, same being the northeast corner of said 1.666 acre tract, Tying in the south line of said 7.654 acre tract, further described as lying in the south line of U.S. Highway 87;

THENCE continuing with the north line of the tract herein described, same being a segment of the common line of said 51.30 acre tract and said 5.000 acre tract with that of said 7.654 acre tract, along a segment of the south line of U.S. Highway 87 as follows:

N 76° 16' 00" E, 275.15 feet (called N 76° 16' E, 276.3 feet) to a railroad spike found In asphalt driveway,

N 81° 58' 38° 5,100.60 feet (called N 82° 12' 5, 99.2 feet) to a one-half inch diameter rebar set

EXHIBIT A

10

Doc                  Bk

eiee.14706                             1342

OP                        703

22760°

754.61

22780-D4N

56.309 ACRES March Z 2008

Page 2

with cap (B&A),

N 76° 16' 04" E, .800.00 feet (called N 76° 14' E, 800.5 feet) to a one-half inch diameter rebar set with cap (B&A),

N 70° 33' 22" E, 100.50 feet (called N 70° 43' E, 101.2 feet) to a concrete right of way marker found broken, and

N 76° 16' 00" E, 464.56 feet (In total called No record call, and N 75° 02''04" E, 278 feet) to aene-half inch diameter rebar set with cap (B&A) marking the northeast corner of the tract herein described, same being the northeast corner of said 5.000 acre tract, lying In-the south line of said 7.654 acre tract, being the northwest corner of a tract called 200.008 acres In Volume 691 at Page 41; said point bears S 76° 16' 00" W, 278.37 feet from an iron pipe found;

THENCE with the east line of the tract herein described, same being a segment of the common line of said 6.000•acre tract and said 51.30 acre tract with that of said 200.008 acre tract as follows:

S 13° 43' 44° E, 78178 feet (called S 15° 01' E, 783.5 feet) to a five-eighths inch diameter rebar found near a two way fence corner marking the east most southeast corner of the tract herein described, same being the southeast

corner of said 6.000 acre tract, re-entrant corner of said 200.008 acre tract,

S 76° 16' 39° W, 277.87 feet (called S 75° D2' 04" W, 278 feet) to a 1Na-eighths inch diameter rebar found marking a re-entrant corner of the tract herein described, same being the southwest corner of said 5.000 acre tract, lying in the east tine of said 51.30 acre tract and being a north corner of said 200.008 acre tract, and

S 13° 24' 23° E, 261.29 feet (called S 13° 24' E, 261.7 feet) to a four inch diameter iron pipe past fence corner marking the south most southeast corner of the tract herein described, same being the-southeast corner of said 51.30 acre tract and re-entrant corner of said 200.008 acre tract;

THENCE with the south line of the tract herein described, same being a segment of the common line of said 51.30 acre tract and said 200.008 acre tract as follows:

S 76° 08' 20" W, 768.00 feet (called S 76° 10' W, 768.0 feet) to a one-half inch diameter rebar set with cap (13&A), and

S 76° 15' 20" W, 1619.78 feet (called S 760 17' W, 1619.8 feet) to a five-eighths inch diameter rebar found near a three way fence corner marking the southWest corner of the tract herein described, same being the southwest corner of said 51.30 acre tract, lying in the north line of said 200.008 acre tract and being the southeast corner of said 41.245 acre tract

THENCE with the west line of the tract herein described, same being the common line of said 51.30 acre beet and said 41.245 acre tract as follows:

N 13° 57' 38" W, 223.50 feet (called N 13" 55' W, 223.5 feet) to a one-half inch diameter rebar set with cap (88A),

N 13° 53' 37" W, 373.70 feet (called N 13° 51' W, 373.7 feet) to a fence post, and

N 13° 49' 38" W, 449.84 feet (called N 13° 47' W, 448.8 feet) to the PLACE OF BEGINNING and containing 56.300 ACRES OP LAND.

I hereby certify that on February 13, 2006 a visual inspection of the tract (field notes„.ph.erei7fore

described) and appeared to be the same as when surveyed o. grounde, s173n in

December 2000.

el L. REI ING R,                                33

11

USDA

United States Department of Agriculture

Rural Development

OFFICE OF THE STATE DIRECTOR

Ms. AnaLiza del Valle, Senior Vice President/SBA Manager American First National Bank 9999 Bellaire Boulevard Houston, Texas 77036 RE: Lazarus Energy, LLC Nixon, Wilson County, Texas Forbearance Agreement Business & Industry Guarantee Loan Servicing — $10,000,000 12 DEC 2012

Dear Ms. del Valle:

This is in response to your October 25, 2012, memorandum and accompanying attachments. You have requested concurrence for the following servicing actions: 1) Extension of the Forbearance Agreement for the period of October 25, 2012, through October 25, 2013; 2) reamortization of the loan; 3) application of the additional payment of $83,333.33 from Genesis Energy, LLC (GEL) to go towards the $526,971.96 accrued interest on the Guaranteed Loan. Once the repaid interest has been paid, the $83,333.33 amount will be deposited into the Payment Reserve Account for a period of 12 months.

As part of previous servicing transaction, both Genesis and Lazarus asked the lender to forbear foreclosing on the refinery for a total of 24 months, split into two 12 months segments.

In the event of continued non-monetary default, the forbearance agreement could be extended for an additional 12 months if all three of the following conditions were met: Lien Holder submitted payments in the amount of either the Tank Storage Fee or Regular Monthly Payment, as applicable, during each of the twelve (12) months of the Forbearance Period; The Services must have been completed under the Construction Contract; The Facility must be operational and generating Gross Profits to the extent that Lien Holder is receiving regular monthly payments.

Based on the information provided, we concur with your request. However, in the event the borrower is unable to make the regular required payments and perform under the terms of the Forbearance Agreement, your lending institution should proceed to maximize recovery. Please note that RD Instruction 4279-A, section 4279.72(a), states in part: "The guarantee will be unenforceable to the extent that any loss is occasioned by a provision of interest on interest."

In the process of reamortizing the loan, please ensure that there is no capitalization of unpaid interest. Compounded interest is prohibited under Agency regulations.

101 South Main - Federal Building, Suite 102. Temple, TX 76501

Phone: (254) 742-9780 • Fax (254) 742-9753 • TDD: (254) 742-97122'• Web: http://www.rurdev.usda cloy

Committed to the future of rural communities.

"USDA is an equal opportunity provider, employer and lender."

To file a complaint of discrimination write USDA, Director, Office of Civil Rights, 1400 Independence Avenue, SW.,

Washington, DC 20250-9410 or call (800) 795-3272 (voice) or (202)720-6382 (TDD).

EXHIBIT B

12

Ms. del Valle                                                                                                              Page 2

In the process of modifying the original promissory note, the original promissory note is not to be terminated. The termination of the original promissory note will cancel the Loan Note Guarantee.

You must ensure that the borrower continues to demonstrate satisfactory progress towards resolving environmental issues.

The Agency acknowledges that the borrower has completed the Blue Dolphin Energy Company transaction without the lender's or Agency's concurrence. We note that your legal counsel has provided an opinion stating that it does not believe that the guaranteed loan and security for such was adversely impacted by the transaction.

Should you have any questions or need additional information, please contact Daniel Torres, Business and Cooperatives Programs Director, or Shelton C. Rhodes, Loan Specialist, at (254) 742-9780.

Sincerely,

/s/ FRANCISCO VALENTIN, JR.

Francisco Valentin, Jr.

State Director

13

EX-10.2

 

Exhibit 10.2

  AMERICAN FIRST NATIONAL BANK

December 13, 2012

Jonathan Carroll, President

Lazarus Energy LLC

801 Travis St., Suite 2100

Houston, TX 77002

Re: Extension of the Forbearance Agreement

Dear Mr. Carroll,

Attached please find the letter from USDA regarding the extension of the Forbearance Agreement.  The extension is good for another year starting October 25, 2012 through October 25, 2013.  A copy of the letter will also be sent to the related parties on the Forbearance Agreement.

If you have further questions, please do not hesitate to phone me.

Sincerely,

/s/ ANALIZA DEL VALLE

AnaLiza del Valle

SVP/SBA Manage

Encl: USDA Letter dated December 12, 2012, extension to the Forbearance Agreement

Cc:           Gel Tex Marketing, LLC

Milam Services

Milam Services, Inc.

Walter A. Schroeder, P.C.

9999 Bellaire Boulevard • Houston, Texas 77036 • Tel: 713-596-2888 • Fax: 713-596-2555

www.AFNB.com

1

USDA

United States Department of Agriculture

Rural Development

OFFICE OF THE STATE DIRECTOR

Ms. AnaLiza del Valle, Senior Vice President/SBA Manager American First National Bank 9999 Bellaire Boulevard Houston, Texas 77036   RE: Lazarus Energy, LLC Nixon, Wilson County, Texas Forbearance Agreement Business & Industry Guarantee Loan Servicing — $10,000,000 12 DEC 2012

Dear Ms. del Valle:

This is in response to your October 25, 2012, memorandum and accompanying attachments. You have requested concurrence for the following servicing actions: 1) Extension of the Forbearance Agreement for the period of October 25, 2012, through October 25, 2013; 2) reamortization of the loan; 3) application of the additional payment of $83,333.33 from Genesis Energy, LLC (GEL) to go towards the $526,971.96 accrued interest on the Guaranteed Loan. Once the repaid interest has been paid, the $83,333.33 amount will be deposited into the Payment Reserve Account for a period of 12 months.

As part of previous servicing transaction, both Genesis and Lazarus asked the lender to forbear foreclosing on the refinery for a total of 24 months, split into two 12 months segments.

In the event of continued non-monetary default, the forbearance agreement could be extended for an additional 12 months if all three of the following conditions were met: Lien Holder submitted payments in the amount of either the Tank Storage Fee or Regular Monthly Payment, as applicable, during each of the twelve (12) months of the Forbearance Period; The Services must have been completed under the Construction Contract; The Facility must be operational and generating Gross Profits to the extent that Lien Holder is receiving regular monthly payments.

Based on the information provided, we concur with your request. However, in the event the borrower is unable to make the regular required payments and perform under the terms of the Forbearance Agreement, your lending institution should proceed to maximize recovery. Please note that RD Instruction 4279-A, section 4279.72(a), states in part: "The guarantee will be unenforceable to the extent that any loss is occasioned by a provision of interest on interest."

In the process of reamortizing the loan, please ensure that there is no capitalization of unpaid interest. Compounded interest is prohibited under Agency regulations.

101 South Main - Federal Building, Suite 102. Temple, TX 76501

Phone: (254) 742-9780 • Fax (254) 742-9753 • TDD: (254) 742-97122'• Web: http://www.rurdev.usda cloy

Committed to the future of rural communities.

"USDA is an equal opportunity provider, employer and lender."

To file a complaint of discrimination write USDA, Director, Office of Civil Rights, 1400 Independence Avenue, SW.,

Washington, DC 20250-9410 or call (800) 795-3272 (voice) or (202)720-6382 (TDD).

2

Ms. del Valle                                                                                                               Page 2

In the process of modifying the original promissory note, the original promissory note is not to be terminated. The termination of the original promissory note will cancel the Loan Note Guarantee.

You must ensure that the borrower continues to demonstrate satisfactory progress towards resolving environmental issues.

The Agency acknowledges that the borrower has completed the Blue Dolphin Energy Company transaction without the lender's or Agency's concurrence. We note that your legal counsel has provided an opinion stating that it does not believe that the guaranteed loan and security for such was adversely impacted by the transaction.

Should you have any questions or need additional information, please contact Daniel Torres, Business and Cooperatives Programs Director, or Shelton C. Rhodes, Loan Specialist, at (254) 742-9780.

Sincerely,

/s/ FRANCISCO VALENTIN, JR.

Francisco Valentin, Jr.

State Director

3

EX-10.3

Exhibit 10.3

AMERICAN FIRST NATIONAL BANK

July 24th , 2013

Jonathan Carroll

Lazarus Energy LLC

801 Travis St., Suite 2100

Houston, TX 77002

Re: $10Million 90% Gty

USDA Ending of the Forbearance Agreement

Dear Mr. Carroll,

Attached please find a copy of the original USDA FIB Note and the Modified Note Agreement on the subject USDA loan. This is a courtesy letter informing you the ending of the forbearance period in August 12, 2013. Please resume payments on the note in the amount of $75,310.35 as reflected on the Note Modified Agreement. Payments on the note will be due on the first day of every month. The payment set forth was based on the re-amortized amount when the note was modified on June 1st, 2013. In addition, the payment reserve must be replenished in accordance with the original FIB Note.

All other loan covenants on the original promissory note will remain the same and active for the life and/or term of the subject note.

If you have further questions, please do not hesitate to phone me.

Regards,

/s/ ANALIZA DEL VALLE

AnaLiza del Valle

SVP/SBA Manage

Encl: FIB Promissory Note, Note Modification Agreement

9999 Bellaire Boulevard • Houston, Texas 77036 • Tel: 713-596-2888 • Fax: 713-596-2555

www.AFNB.com

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: August 14, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 14, 2013	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended June 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: August 14, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended June 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Interim Chief Financial Officer, Treasurer and Assistant Secretary (PrincipalFinancial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

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

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11. Property, Plant and Equipment, Net

6 Months Ended

Jun. 30, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	June 30,		December 31,
	2013		2012
Refinery and facilities	$	34,734,307	$	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		443,939		577,567
		37,315,457		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,334,665		1,674,151
		34,980,792		35,040,826
Construction in Progress		907,748		821,259
Property, Plant and Equipment, Net	$	35,888,540	$	35,862,085

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7. Concentration of Risk (Details)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Concentration Risk	100.00%	100.00%
Low-sulfur diesel
Concentration Risk	49.80%	45.60%
Naphtha
Concentration Risk	26.30%	26.80%
Atmospheric gas oil
Concentration Risk	23.80%	27.10%
Reduced crude [Member]
Concentration Risk	0.00%	0.00%

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
REVENUE FROM OPERATIONS
Refined product sales	$ 104,312,768	$ 84,416,296	$ 213,484,275	$ 130,187,259
Pipeline operations	77,105	124,476	150,253	194,386
Oil and gas sales		1,226		7,282
Total revenue from operations	104,389,873	84,541,998	213,634,528	130,388,927
COST OF OPERATIONS
Cost of refined products sold	105,871,717	88,051,229	212,194,378	133,692,455
Refinery operating expenses	2,724,644	2,239,914	5,469,853	3,302,665
Pipeline operating expenses	36,408	127,502	81,779	237,120
Lease operating expenses	14,390	25,621	41,291	44,959
General and administrative expenses	461,539	734,720	946,103	1,260,307
Depletion, depreciation and amortization	331,727	463,028	660,515	718,781
Abandonment expense	23,901		51,352
Accretion expense	31,177	29,189	56,340	50,750
Total cost of operations	109,495,503	91,671,203	219,501,611	139,307,037
Loss from operations	(5,105,630)	(7,129,205)	(5,867,083)	(8,918,110)
OTHER INCOME (EXPENSE)
Net tank rental revenue	278,349	81,364	556,699	175,319
Interest and other income	977	2,265	1,812	3,915
Interest expense	(280,706)	(275,333)	(561,769)	(508,850)
Total other expense	(1,380)	(191,704)	(3,258)	(329,616)
Loss from continuing operations before income taxes	(5,107,010)	(7,320,909)	(5,870,341)	(9,247,726)
Tax expense Current		17,419		(13,144)
Tax expense Deferred
Income tax (expense) benefit	0	17,419	0	(13,144)
Loss from continuing operations, net of tax	(5,107,010)	(7,303,490)	(5,870,341)	(9,260,870)
Loss from discontinued operations, net of tax		(94,344)		(106,858)
Net loss	$ (5,107,010)	$ (7,397,834)	$ (5,870,341)	$ (9,367,728)
Basic loss per common share
Continuing operations	$ (0.49)	$ (0.69)	$ (0.56)	$ (0.93)
Discontinued operations		$ (0.01)		$ (0.01)
Basic loss per common share	$ (0.49)	$ (0.70)	$ (0.56)	$ (0.94)
Diluted loss per common share
Continuing operations	$ (0.49)	$ (0.69)	$ (0.56)	$ (0.93)
Discontinued operations		$ (0.01)		$ (0.01)
Diluted loss per common share	$ (0.49)	$ (0.70)	$ (0.56)	$ (0.94)
Weighted average number of common shares outstanding:
Basic	10,421,629	10,541,853	10,465,736	10,002,926
Diluted	10,421,629	10,541,853	10,465,736	10,002,926

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4. Business Segment Information

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Business Segment Information

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

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

	Three Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	104,312,768		$	77,105		$	-		$	-		$	104,389,873
Operation cost(2)		(108,600,407	)		(122,066	)		(42,395	)		(398,908	)		(109,163,776	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(4,009,290	)	$	(44,961	)	$	(42,395	)	$	(398,908	)
Depletion, depreciation and amortization														(331,727	)
Other income (expense), net														(279,729	)
Loss from continuing operations,
before income taxes													$	(5,107,010	)
Loss from discontinued operations													$	-
Capital expenditures	$	357,744		$	-		$	-		$	-		$	357,744
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $212,001 and an unrealized gain of $79,200.
(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 June 30, 2012 (and at June 30, 2012) were as follows:

	Three Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	84,416,296		$	124,476		$	1,226		$	-		$	84,541,998
Operation cost(2)		(90,369,807	)		(241,503	)		(218,085	)		(378,780	)		(91,208,175	)
Other non-interest income		81,364			-			-			-			81,364
EBITDA	$	(5,872,147	)	$	(117,027	)	$	(216,859	)	$	(378,780	)
Depletion, depreciation and amortization														(463,028	)
Other income (expense), net														(273,068	)
Loss from continuing operations,
before income taxes													$	(7,320,909	)
Loss from discontinued operations													$	(94,344	)
Capital expenditures	$	724,805		$	-		$	-		$	-		$	724,805
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

__________________________

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

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

	Six Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	213,484,275		$	150,253		$	-		$	-		$	213,634,528
Operation cost(2)		(217,664,084	)		(218,901	)		(100,059	)		(858,052	)		(218,841,096	)
Other non-interest income		556,699			-			-			-			556,699
EBITDA	$	(3,623,110	)	$	(68,648	)	$	(100,059	)	$	(858,052	)
Depletion, depreciation and amortization														(660,515	)
Other income (expense), net														(559,957	)
Loss from continuing operations, before income taxes													$	(5,870,341	)
Loss from discontinued operations													$	-
Capital expenditures	$	887,970		$	-		$	-		$	-		$	887,970
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $248,441 and an unrealized gain of $215,300.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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

	Six Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	130,187,259		$	194,386		$	7,282		$	-		$	130,388,927
Operation cost(2)		(137,232,245	)		(437,220	)		(422,372	)		(496,419	)		(138,588,256	)
Other non-interest income		175,319			-			-			-			175,319
EBITDA	$	267,594,823		$	631,606		$	429,654		$	496,419
Depletion, depreciation and amortization														(718,781	)
Other income (expense), net														(504,935	)
Loss from continuing operations, before income taxes													$	(9,247,726	)
Loss from discontinued operations													$	(106,858	)
Capital expenditures	$	2,074,137		$	-		$	-		$	-		$	2,074,137
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

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

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18. Leases

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum monthly payment is $9,463 per month. The office lease agreement provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. For the three months ended June 30, 2013 and 2012, rent expense for the office lease was $25,161 and $28,344, respectively. For the six months ended June 30, 2013 and 2012, rent expense for the office lease was $51,221 and $52,121, respectively.

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

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10. Inventories (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 1,054,402	$ 397,240
Naphtha	1,510,195	1,562,055
Atmospheric gas oil	750,476	322,356
Crude	19,041	19,041
Inventories, Net	$ 3,334,114	$ 2,300,692

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12. Discontinued Operations

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Discontinued Operations

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

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Revenue	$	-	$	248,855		$	-	$	443,139
Lease operating expenses		-		273,341			-		455,716
Depletion, depreciation and amortization		-		57,362			-		79,571
Accretion expense		-		12,496			-		14,710
Total costs and expenses		-		343,199			-		549,997
Loss from discontinued operations, net of tax	$	-	$	(94,344	)	$	-	$	(106,858	)

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5. Fair Value Measurement (Details) (USD $)	Jun. 30, 2013
Financial liabilties:
Commodity contracts	$ 79,200
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	79,200
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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11. Property, Plant and Equipment, Net (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Property Plant And Equipment Net Details
Less: Accumulated depletion, depreciation and amortization	$ 2,334,665	$ 1,674,151
Property, Plant and Equipment less depreciation	34,980,792	35,040,826
Construction in Progress	907,748	821,259
Property, Plant and Equipment, Net	$ 35,888,540	$ 35,862,085

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

6 Months Ended

Jun. 30, 2013

Property, Plant and Equipment [Abstract]

Property and equipment

Property and equipment consisted of the following:

	June 30,		December 31,
	2013		2012
Refinery and facilities	$	34,734,307	$	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		443,939		577,567
		37,315,457		36,714,977
Less:  Accumulated depletion, depreciation and amortization		2,334,665		1,674,151
		34,980,792		35,040,826
Construction in Progress		907,748		821,259
Property, Plant and Equipment, Net	$	35,888,540	$	35,862,085

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21. Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Management Agreement

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

Genesis Agreements

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

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL, an affiliate of Genesis, is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. 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 Note 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 modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. 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 $64,358 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees. In addition, Milam and GEL incurred legal fees and expenses related to settling the matter. In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

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

As of June 30, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $8,850,775. As of June 30, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $5,395,050.

Refinery Note

As of June 30, 2013, the principal balance outstanding on the Refinery Note was $9,256,114. During the three months ended June 30, 2013, GEL paid AFNB in the amount of $178,646 to repay all Arrearages.

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

Lazarus Energy Development, LLC (“LED”) Option

In connection with the Merger, we purchased an exclusive option, which expires on 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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20. Income Taxes

6 Months Ended

Jun. 30, 2013

Income Tax Disclosure [Abstract]

Income Taxes

LE is a limited liability company and, prior to the Merger, its taxable income or net operating losses (“NOLs”) flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon the Merger, LE became the subsidiary of Blue Dolphin and LE’s taxable income or NOLs flowed through to Blue Dolphin for federal and state income tax purposes. However, Section 382 of the Internal Revenue Code imposes a limitation on Blue Dolphin’s use of LE’s NOLs. The amount of NOLs subject to such limitations is approximately $18.5 million. Nevertheless, the NOLs generated subsequent to the Merger, approximately $13.3 million, is not subject to any such limitation. For the three and six months ended June 30, 2013, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended June 30, 2013 and 2012, income tax expense was $0 and income tax benefit was $17,419, respectively. For the six months ended June 30, 2013 and 2012, income tax expense was $0 and $13,144, respectively. Income tax expense and benefit related to the State of Texas margins tax (“TMT”). TMT is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.

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4. Business Segment Information (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues	$ 104,389,873	$ 84,541,998	$ 213,634,528	$ 130,388,927
Operation cost		343,199
Depletion, depreciation and amortization	331,727	463,028	660,515	718,781
Loss from discontinued operations		(94,344)		(106,858)
Crude Oil and Condensate Processing [Member]
Revenues	104,312,768	84,416,296	213,484,275	130,187,259
Operation cost	(108,600,407)	(90,369,807)	(217,664,084)	(137,232,245)
Other non-interest income	278,349	81,364	556,699	175,319
EBITDA	(4,009,290)	(5,872,147)	(3,623,110)	267,594,823
Capital expenditures	357,744	724,805	887,970	2,074,137
Identifiable assets	47,519,385	44,975,160	47,519,385	44,975,160
Segment Pipeline Transportation [Member]
Revenues	77,105	124,476	150,253	194,386
Operation cost	(122,066)	(241,503)	(218,901)	(437,220)
Other non-interest income
EBITDA	(44,961)	(117,027)	(68,648)	631,606
Capital expenditures
Identifiable assets	1,620,019	11,914,226	1,620,019	11,914,226
Oil & Gas Exploration and Production [Member]
Revenues		1,226		7,282
Operation cost	(42,395)	(218,085)	(100,059)	(422,372)
Other non-interest income
EBITDA	(42,395)	(216,859)	(100,059)	429,654
Capital expenditures
Identifiable assets	19,299	5,506,385	19,299	5,506,385
Corporate & Other [Member]
Revenues
Operation cost	(398,908)	(378,780)	(858,052)	(496,419)
Other non-interest income
EBITDA	(398,908)	(378,780)	(858,052)	496,419
Capital expenditures
Identifiable assets	778,160	1,014,185	778,160	1,014,185
Total
Revenues	104,389,873	84,541,998	213,634,528	130,388,927
Operation cost	(109,163,776)	(91,208,175)	(218,841,096)	(138,588,256)
Other non-interest income	278,349	81,364	556,699	175,319
Depletion, depreciation and amortization	(331,727)		(660,515)	(718,781)
Other income (expense), net	(279,729)	(273,068)	(559,957)	(504,935)
Income (loss) before taxes	(5,107,010)	(7,320,909)	(5,870,341)	(9,247,726)
Loss from discontinued operations		(94,344)		(106,858)
Capital expenditures	357,744	724,805	887,970	2,074,137
Identifiable assets	$ 49,936,863	$ 63,409,956	$ 49,936,863	$ 63,409,956

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7. Concentration of Risk (Tables)

6 Months Ended

Jun. 30, 2013

Concentration Of Risk Tables

Percentages of all refined petroleum products sales to total sales

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

	Six Months Ended June 30,
	2013			2012
Low-sulfur diesel		49.8	%		45.6	%
Naphtha		26.3	%		26.8	%
Atmospheric gas oil		23.8	%		27.1	%
Reduced crude		0.1	%		0.5	%
		100.0	%		100.0	%

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15. Accrued Expenses and Other Current Liabilities (Tables)

6 Months Ended

Jun. 30, 2013

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consisted of the following:

	June 30,		December 31,
	2013		2012
Excise taxes	$	283,640	$	292,303
Turnaround expenses		63,646		-
Transportation		-		69,551
Other payable		252,199		134,501
Property taxes		27,000		-
Insurance		22,440		-
Unrealized hedging loss		-		136,100
Unearned revenue		65,000		92,783
	$	713,925	$	725,238

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5. Fair Value Measurement (Details Narrative) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Fair Value Measurement Details Narrative
Fair value of longer term debt	$ 19,453,025	$ 15,850,418

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4. Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Business segment reporting

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

	Three Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	104,312,768		$	77,105		$	-		$	-		$	104,389,873
Operation cost(2)		(108,600,407	)		(122,066	)		(42,395	)		(398,908	)		(109,163,776	)
Other non-interest income		278,349			-			-			-			278,349
EBITDA	$	(4,009,290	)	$	(44,961	)	$	(42,395	)	$	(398,908	)
Depletion, depreciation and amortization														(331,727	)
Other income (expense), net														(279,729	)
Loss from continuing operations,
before income taxes													$	(5,107,010	)
Loss from discontinued operations													$	-
Capital expenditures	$	357,744		$	-		$	-		$	-		$	357,744
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $212,001 and an unrealized gain of $79,200.
(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 June 30, 2012 (and at June 30, 2012) were as follows:

	Three Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	84,416,296		$	124,476		$	1,226		$	-		$	84,541,998
Operation cost(2)		(90,369,807	)		(241,503	)		(218,085	)		(378,780	)		(91,208,175	)
Other non-interest income		81,364			-			-			-			81,364
EBITDA	$	(5,872,147	)	$	(117,027	)	$	(216,859	)	$	(378,780	)
Depletion, depreciation and amortization														(463,028	)
Other income (expense), net														(273,068	)
Loss from continuing operations,
before income taxes													$	(7,320,909	)
Loss from discontinued operations													$	(94,344	)
Capital expenditures	$	724,805		$	-		$	-		$	-		$	724,805
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

__________________________

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

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

	Six Months Ended June 30, 2013
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	213,484,275		$	150,253		$	-		$	-		$	213,634,528
Operation cost(2)		(217,664,084	)		(218,901	)		(100,059	)		(858,052	)		(218,841,096	)
Other non-interest income		556,699			-			-			-			556,699
EBITDA	$	(3,623,110	)	$	(68,648	)	$	(100,059	)	$	(858,052	)
Depletion, depreciation and amortization														(660,515	)
Other income (expense), net														(559,957	)
Loss from continuing operations, before income taxes													$	(5,870,341	)
Loss from discontinued operations													$	-
Capital expenditures	$	887,970		$	-		$	-		$	-		$	887,970
Identifiable assets(3)	$	47,519,385		$	1,620,019		$	19,299		$	778,160		$	49,936,863

__________________________

(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 $248,441 and an unrealized gain of $215,300.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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

	Six Months Ended June 30, 2012
	Segment
	Crude Oil						Oil and Gas
	and Condensate			Pipeline			Exploration &			Corporate &
	Processing			Transportation			Production			Other(1)			Total
Revenues	$	130,187,259		$	194,386		$	7,282		$	-		$	130,388,927
Operation cost(2)		(137,232,245	)		(437,220	)		(422,372	)		(496,419	)		(138,588,256	)
Other non-interest income		175,319			-			-			-			175,319
EBITDA	$	267,594,823		$	631,606		$	429,654		$	496,419
Depletion, depreciation and amortization														(718,781	)
Other income (expense), net														(504,935	)
Loss from continuing operations, before income taxes													$	(9,247,726	)
Loss from discontinued operations													$	(106,858	)
Capital expenditures	$	2,074,137		$	-		$	-		$	-		$	2,074,137
Identifiable assets(3)	$	44,975,160		$	11,914,226		$	5,506,385		$	1,014,185		$	63,409,956

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

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17. Long-Term Debt (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery Note	$ 9,256,114	$ 9,298,183
Construction and Funding Agreement	8,850,775	5,206,175
Notre Dame Debt	1,300,000	1,300,000
Captial Leases		2,119
Total	19,406,889	15,806,477
Less: Current portion of long-term debt	10,741,114	1,816,960
Long term debt	$ 8,665,775	$ 13,989,517

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23. Stock Options (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Issuance of restricted common stock expense			$ 14,642
Expense related to the fair value issuance of restricted common stock	$ 0	$ 99,000	$ 50,000	$ 119,000

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16. Asset Retirement Obligations (Details Narrative) (USD $)	3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2012
Asset Retirement Obligations Details Narrative
Abandonment expense	$ 23,901	$ 51,352	$ (3,685)

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22. Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Earnings per share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Loss from continuing operations, net of tax	$	(5,107,010	)	$	(7,303,490	)	$	(5,870,341	)	$	(9,260,870	)
Loss from discontinued operations, net of tax		-			(94,344	)		-			(106,858	)
Net loss		(5,107,010	)		(7,397,834	)		(5,870,341	)		(9,367,728	)
Basic and diluted loss per common share
Continuing operations	$	(0.49	)	$	(0.69	)	$	(0.56	)	$	(0.93	)
Discontinued operations	$	-		$	(0.01	)	$	-		$	(0.01	)
Basic and diluted loss per common share	$	(0.49	)	$	(0.70	)	$	(0.56	)	$	(0.94	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,629			10,541,853			10,465,736			10,002,926

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21. Commitments and Contingencies (Details Narrative) (USD $)	3 Months Ended
	Jun. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Advances and Deficit Amounts	$ 8,850,775
Deficit Amount under the Construction and Funding Agreement	5,395,050
Principal balance outstanding on the Refinery Note	9,256,114
Repay all Arrearages	$ 178,646

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19. Treasury Stock

6 Months Ended

Jun. 30, 2013

Equity [Abstract]

Treasury Stock

On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia. The non-cash transaction was completed on February 28, 2013. Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of common stock, which represented a recovery of a significant portion of the 342,857 shares of common stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock. As of June 30, 2013, there were 150,000 shares of treasury stock.

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Condensed Consolidated Statements of Cash Flows (Parenthetical) (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Statement of Cash Flows [Abstract]
Cash acquired from business acquisition	$ 1,674,594	$ 1,674,594

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2. Basis of Presentation

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Basis of Presentation

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

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

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5. Fair Value Measurement

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at June 30, 2013 and December 31, 2012 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at June 30, 2013 and December 31, 2012 was $19,453,025 and $15,850,418, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and the basis for that measurement:

			Fair Value Measurement at June 30, 2013 Using
Financial assets:	Carrying Value as at June 30, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	79,200	$	79,200	$	-	$	-

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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3. Significant Accounting Policies

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

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

Use of Estimates

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

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $180,819 and $420,896 at June 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,367 and $89,593 at June 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. We had uninsured balances of $0 and $170,896 at June 30, 2013 and December 31, 2012, respectively.

For the three months ended June 30, 2013, we had four customers that accounted for approximately 81% of our refined petroleum product sales. These four customers represented approximately $6.6 million in accounts receivable at June 30, 2013. For the six months ended June 30, 2013, we had five customers that accounted for approximately 91% of our refined petroleum product sales. These five customers represented approximately $7.5 million in accounts receivable at June 30, 2013.

For the three months ended June 30, 2012, we had three customers that accounted for approximately 79% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012. For the six months ended June 30, 2012, we had three customers that accounted for approximately 69% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012.

Inventory

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

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, we record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three and six months ended June 30, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three and six months ended June 30, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

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

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

Intangibles – Goodwill and Other

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

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

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

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

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

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

Debt Issue Costs

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

Debt issue costs, net of accumulated amortization, totaled $515,435 and $532,335 at June 30, 2013 and December 31, 2012, respectively. Accumulated amortization was $160,545 and $143,645 at June 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note. For the three and six months ended June 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. For the three and six months ended June 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. See “Note (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

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

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

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

Income Taxes

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

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards. See “Note (20) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Treasury Stock

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

Business Combinations

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

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

Reclassification

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

New Pronouncements Issued but Not Yet Effective

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

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16. Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 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 at December 31, 2012	$	921,260
Liabilities settled		(8,244	)
Accretion expense		56,341
		969,357
Less:  current portion of asset retirement obligations		85,347
Asset retirement obligations, long-term balance
at June 30, 2013	$	884,010

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22. Earnings Per Share

6 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Loss from continuing operations, net of tax	$	(5,107,010	)	$	(7,303,490	)	$	(5,870,341	)	$	(9,260,870	)
Loss from discontinued operations, net of tax		-			(94,344	)		-			(106,858	)
Net loss		(5,107,010	)		(7,397,834	)		(5,870,341	)		(9,367,728	)
Basic and diluted loss per common share
Continuing operations	$	(0.49	)	$	(0.69	)	$	(0.56	)	$	(0.93	)
Discontinued operations	$	-		$	(0.01	)	$	-		$	(0.01	)
Basic and diluted loss per common share	$	(0.49	)	$	(0.70	)	$	(0.56	)	$	(0.94	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,421,629			10,541,853			10,465,736			10,002,926

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 and six months ended June 30, 2013 and 2012 excludes stock options outstanding as they would be anti-dilutive.

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

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5. Fair Value Measurement (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurement

The following table represents our assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and the basis for that measurement:

			Fair Value Measurement at June 30, 2013 Using
Financial assets:	Carrying Value as at June 30, 2013		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	79,200	$	79,200	$	-	$	-

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23. Stock Options (Details) (USD $)	6 Months Ended
	Jun. 30, 2013
Shares
Options outstanding at December 31, 2012	14,642
Options granted
Options exercised
Options expired or cancelled
Options outstanding at June 30, 2013	14,642
Options outstanding at June 30, 2013	14,642
Weighted Average Exercise Price
Options outstanding at December 31, 2012
Options granted
Options exercised
Options expired or cancelled
Options outstanding at June 30, 2013	$ 19.67
Options outstanding at June 30, 2013	$ 19.67
Weighted Average Remaining Contractual Life
Options outstanding at June 30, 2013	4 months 24 days
Options outstanding at June 30, 2013	4 months 24 days
Aggregate Intrinisic Value
Options outstanding at June 30, 2013
Options outstanding at June 30, 2013

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10. Inventories (Tables)

6 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories balances

Inventory balances consisted of the following:

	June 30,		December 31,
	2013		2012
Low-sulfur diesel	$	1,054,402	$	397,240
Naphtha		1,510,195		1,562,055
Atmospheric gas oil		750,476		322,356
Crude		19,041		19,041
	$	3,334,114	$	2,300,692

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22. Earnings per share (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Earnings Per Share [Abstract]
Income (loss) from continuing operations, net of tax	$ (5,107,010)	$ (7,303,490)	$ (5,870,341)	$ (9,260,870)
Loss from discontinued operations, net of tax		(94,344)		(106,858)
Net income (loss)	$ (5,107,010)	$ (7,397,834)	$ (5,870,341)	$ (9,367,728)
Basic and diluted earnings (loss) per common share
Continuing operations	$ (0.49)	$ (0.69)	$ (0.56)	$ (0.93)
Discontinued operations		$ (0.01)		$ (0.01)
Basic and diluted earnings (loss) per common share	$ (0.49)	$ (0.70)	$ (0.56)	$ (0.94)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,421,629	10,541,853	10,465,736	10,002,926

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9. Deposits (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Deposits Details
Utility deposits	$ 31,250	$ 36,500
Equipment deposits	124,526	124,526
Tax bonds	792,000	792,000
Purchase option deposits	283,421	283,421
Rent deposits	9,463	0
Deposits	$ 1,240,660	$ 1,236,447

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

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3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Accounting Policies [Abstract]
Restricted cash	$ 27,367		$ 27,367		$ 89,593
Perecentage of revenue from major customers	81.00%	79.00%	91.00%	69.00%
Three major customers accounts recievable					3,400,000
Four major customers accounts recievable	6,600,000		6,600,000
Five major customers accounts recievable	7,500,000		7,500,000
Accumulated amortization	160,545		160,545		143,645
Uninsured balances	0		0		170,896
Amortization expense	143,645		143,645
Debt issuance costs	515,435		515,435		532,335
Non-cash impairment charge					$ 1,445,720
Impairment charge representation in goodwill					100.00%

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Jun. 30, 2013	Dec. 31, 2012
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,571,629	10,563,297
Common stock, shares outstanding	10,571,629	10,563,297

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8. Prepaid Expenses and Other Current Assets

6 Months Ended

Jun. 30, 2013

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

Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	June 30,		December 31,
	2013		2012
Prepaid insurance	$	101,673	$	185,814
Prepaid restructuring fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		79,200		-
	$	264,386	$	228,314

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
OPERATING ACTIVITIES
Net loss	$ (5,870,341)	$ (9,367,728)
Loss from discontinued operations		106,858
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	660,515	713,071
Unrealized loss (gain) on derivatives	(215,300)	126,983
Amortization of debt issue costs	16,900	16,899
Amortization of intangible assets	9,463	5,710
Accretion expense	56,340	50,750
Abandonment costs incurred	51,352	(3,685)
Common stock issued for services	50,000	119,000
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash	62,226	(538)
Accounts receivable	6,416,559	(5,589,773)
Prepaid expenses and other current assets	(36,072)	24,272
Deposits	(4,213)	(775,921)
Inventory	(1,033,422)	810,594
Accounts payable, accrued expenses and other liabilities	(4,233,122)	8,736,277
Accounts payable, related party	913,401	2,022,546
Net cash provided by (used in) operating activities - continuing operations	(3,155,714)	(3,004,685)
Net cash provided by operating activities - discontinued operations		(12,577)
Net cash used in operating activities	(3,155,714)	(3,017,262)
INVESTING ACTIVITIES
Capital expenditures	(887,970)	(2,074,137)
Proceeds from sale of assets	201,000
Cash acquired on Acquisition		1,674,594
Net cash used in investing activities	(686,970)	(399,543)
FINANCING ACTIVITIES
Proceeds from issuance of debt	3,705,191	4,252,847
Payments on long term debt	(60,876)	(356,651)
Proceeds from notes payable	15,032	16,000
Payments on notes payable	(56,740)	(18,925)
Net cash provided by financing activities	3,602,607	3,893,271
Net increase (decrease) in cash and cash equivalents	(240,077)	476,466
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	420,896	1,822
CASH AND CASH EQUIVALENTS AT END OF PERIOD	180,819	478,288
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	800,000
Non-cash investing and financing activities:
Financing of insurance premiums		82,560
Related party payable converted to equity		993,732
Acquisition of Blue Dolphin at fair value, inclusive of cash acquired of $1,674,594		18,046,154
Shares issued for services	$ 50,000	$ 119,000

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12. Discontinued Operations (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenue	$ 104,389,873	$ 84,541,998	$ 213,634,528	$ 130,388,927
Lease operating expenses		273,341
Depletion, depreciation and amortization	331,727	463,028	660,515	718,781
Accretion expense		12,496
Total costs and expenses		343,199
Loss from discontinued operations, net of tax		(94,344)		(106,858)
Discontinued Operations
Revenue				443,139
Lease operating expenses				455,716
Depletion, depreciation and amortization				79,571
Accretion expense				14,710
Total costs and expenses				549,997
Loss from discontinued operations, net of tax				$ (106,858)

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 180,819	$ 420,896
Restricted cash	27,367	89,593
Accounts receivable, net	8,182,196	15,398,755
Prepaid expenses and other current assets	264,386	228,314
Deposits	1,240,660	1,236,447
Inventory	3,334,114	2,300,692
Total current assets	13,229,542	19,674,697
Total property and equipment, net	35,888,540	35,862,085
Debt issue costs, net	515,435	532,335
Other assets		9,463
Trade name	303,346	303,346
TOTAL ASSETS	49,936,863	56,381,926
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	14,753,545	19,171,013
Accounts payable, related party	2,507,422	1,594,021
Note payable	46,136	43,941
Asset retirement obligations, current portion	85,347
Accrued expenses and other current liabilities	713,925	725,238
Interest payable, current portion	577,139	640,352
Long-term debt, current portion	10,741,114	1,816,960
Total current liabilities	29,424,628	23,991,525
Asset retirement obligations, net of current portion	884,010	921,260
Long term debt, net of current portion	8,665,775	13,989,517
Long term interest payable, net of current portion	961,929	858,784
Total long-term liabilities	10,511,714	15,769,561
TOTAL LIABILITIES	39,936,342	39,761,086
Commitments and contingencies
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,571,629 and 10,563,297 shares issued and outstanding at June 30, 2013 and December 31, 2012, respectively)	105,717	105,633
Additional paid-in capital	36,574,059	36,524,142
Accumulated deficit	(25,879,255)	(20,008,935)
Treasury stock, 150,000 and 0 shares, respectively, at cost	(800,000)
Total stockholders' equity	10,000,521	16,620,840
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 49,936,863	$ 56,381,926

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts [Member], USD $)	Jun. 30, 2013	Dec. 31, 2012
Commodity Contracts [Member]
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 79,200	$ (136,100)

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23. Stock Options

6 Months Ended

Jun. 30, 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 approved continuation of the Plan following Blue Dolphin’s reverse merger with LE.

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

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

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

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at June 30, 2013		14,642	$	19.67		0.4	$	-
Options exercisable at June 30, 2013		14,642	$	19.67		0.4	$	-

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

For the three and six months ended June 30, 2013, we recognized $0 and $50,000 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered. For the three and six months ended June 30, 2012, we recognized $99,000 and $119,000 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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17. Long-Term Debt

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Long-Term Debt

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

	June 30,		December 31,
	2013		2012
Refinery Note	$	9,256,114	$	9,298,183
Construction and Funding Agreement		8,850,775		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Captial Leases		-		2,119
		19,406,889		15,806,477
Less: Current portion of long-term debt		10,741,114		1,816,960
	$	8,665,775	$	13,989,517

Refinery Note. On September 29, 2008 LE entered into a loan agreement (the “Loan Agreement”) with First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000 (the “Refinery Note”). The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at June 30, 2013) and has a maturity date of October 1, 2028 (the “Maturity Date”). LE’s obligations under the Refinery Note are secured by a Deed of Trust (the “Deed of Trust”) of even date with the Loan Agreement. The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Loan Agreement, the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE. Previously, we were in default under our Refinery Loan Documents and, on August 12, 2011, the Loan Agreement and Refinery Note were subject to a forbearance agreement (the “Forbearance Agreement”). The principal balance outstanding on the Refinery Note was $9,256,114 and $9,298,183 at June 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Refinery Note in the amount of $38,181 and $250,070 at June 30, 2013 and December 31, 2012, respectively.

Pursuant to the Forbearance Agreement, FIB agreed to forbear further from exercising its rights and remedies under the Refinery Loan Documents in order to permit us to pay all arrearages and fees (the “Arrearages”). The Forbearance Agreement commenced on August 12, 2011 and expired on August 12, 2013. To date, all Arrearages have been fully paid. In addition, the Loan Agreement and the Refinery Note are no longer subject to the Forbearance Agreement, and the Refinery Loan Documents have been fully reinstated in accordance with the terms and conditions thereof. The Loan Agreement has various financial covenants relating to a current ratio and debt to net worth. If currently measured, we would be in violation of these covenants. We do not expect to cure these violations before the next measurement date, which is September 30, 2013. As a resault, the Refinery Note has been included in the current portion of long-term debt on the condensed consolidated balance sheet as of June 30, 2013.

In October 2011, the Refinery Loan Documents were acquired by American First National Bank (“AFNB”). On June 1, 2013, AFNB and LE amended the Refinery Note (the “Note Modification Agreement”). Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310. Other than modification of the payment terms under the Refinery Note, the terms under the Loan Agreement and the Refinery Note remain the same through the Maturity Date and the Refinery Loan Documents remain in full force and effect.

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations. We started making payments under the Construction and Funding Agreement in the first quarter of 2012. All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually. The principal balance outstanding on the Construction and Funding Agreement was $8,850,775 and $5,206,175 at June 30, 2013 and December 31, 2012, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $536,052 and $386,695 at June 30, 2013 and December 31, 2012, respectively. There are no financial covenants associated with this obligation.

See “Note (21) 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.

Notre Dame Debt. LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8,000,000, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at a default rate of 16% and is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at June 30, 2013 and December 31, 2012. Interest was accrued on the Notre Dame Debt in the amount of $961,929 and $858,784 at June 30, 2013 and December 31, 2012, respectively. There are no financial covenants associated with the Notre Dame Debt.

Pursuant to an Intercreditor and Subordination Agreement dated September 29, 2008, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of the holder of the Refinery Note, the Deed of Trust and Security Agreement.

Pursuant to an Intercreditor and Subordination Agreement dated August 12, 2011, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of Milam under the Construction and Funding Agreement.

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

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23. Stock Options (Tables)

6 Months Ended

Jun. 30, 2013

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

Stock options activity table

A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)		Aggregate Intrinsic Value
Options outstanding at December 31, 2012		14,642	$	-
Options granted		-	$	-
Options exercised		-	$	-
Options exercised or cancelled		-	$	-
Options outstanding at June 30, 2013		14,642	$	19.67		0.4	$	-
Options exercisable at June 30, 2013		14,642	$	19.67		0.4	$	-

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8. Prepaid Expenses and Other Current Assets (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 101,673	$ 185,814
Prepaid restructing fees	50,000
Employee advances		22,500
Prepaid loan closing fees	33,513	20,000
Unrealized hedging gains	79,200
Prepaid Expenses, Net	$ 264,386	$ 228,314

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17. Long-Term Debt (Details Narrative) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Refinery note accrued interest	$ 38,181	$ 250,070
Notre Dame debt accrued interest	961,929	858,784
Construction funding accrued interest	536,052	386,695
Capital leases	$ 0	$ 2,119
Effective rate	5.50%

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12. Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2013

Discontinued Operations Tables

Operating results of discontinued operations

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Revenue	$	-	$	248,855		$	-	$	443,139
Lease operating expenses		-		273,341			-		455,716
Depletion, depreciation and amortization		-		57,362			-		79,571
Accretion expense		-		12,496			-		14,710
Total costs and expenses		-		343,199			-		549,997
Loss from discontinued operations, net of tax	$	-	$	(94,344	)	$	-	$	(106,858	)

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8. Prepaid Expenses and Other Current Assets (Tables)

6 Months Ended

Jun. 30, 2013

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid balances consisted of the following:

	June 30,		December 31,
	2013		2012
Prepaid insurance	$	101,673	$	185,814
Prepaid restructuring fees		50,000		-
Employee advances		-		22,500
Prepaid loan closing fees		33,513		20,000
Unrealized hedging gains		79,200		-
	$	264,386	$	228,314

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9. Deposits (Tables)

6 Months Ended

Jun. 30, 2013

Deposits Tables

Deposit balances

Deposit balances consisted of the following:

	June 30,		December 31,
	2013		2012
Utility deposits	$	31,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,240,660	$	1,236,447

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7. Concentration of Risk

6 Months Ended

Jun. 30, 2013

Risks and Uncertainties [Abstract]

Concentration of Risk

Key Supplier. GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis, 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 of our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products.

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

	Six Months Ended June 30,
	2013			2012
Low-sulfur diesel		49.8	%		45.6	%
Naphtha		26.3	%		26.8	%
Atmospheric gas oil		23.8	%		27.1	%
Reduced crude		0.1	%		0.5	%
		100.0	%		100.0	%

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16. Asset Retirement Obligations (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Asset Retirement Obligations Details
Asset retirment obligations at December 31, 2012			$ 921,260
Liabilities settled			(8,244)
Accretion expense	31,177	29,189	56,340	50,750
Asset retirement obligations as of June 30, 2013	969,357		969,357
Less current portion of asset retirement obligations	85,347		85,347
Asset retirement obligations, long-term balance at June 30, 2013	$ 884,010		$ 884,010		$ 921,260

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3. Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Basis of presentation

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

Use of Estimates

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

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $180,819 and $420,896 at June 30, 2013 and December 31, 2012, respectively.

Restricted Cash

Restricted cash was $27,367 and $89,593 at June 30, 2013 and December 31, 2012, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. We had uninsured balances of $0 and $170,896 at June 30, 2013 and December 31, 2012, respectively.

For the three months ended June 30, 2013, we had four customers that accounted for approximately 81% of our refined petroleum product sales. These four customers represented approximately $6.6 million in accounts receivable at June 30, 2013. For the six months ended June 30, 2013, we had five customers that accounted for approximately 91% of our refined petroleum product sales. These five customers represented approximately $7.5 million in accounts receivable at June 30, 2013.

For the three months ended June 30, 2012, we had three customers that accounted for approximately 79% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012. For the six months ended June 30, 2012, we had three customers that accounted for approximately 69% of our refined petroleum product sales. These three customers represented approximately $3.4 million in accounts receivable at June 30, 2012.

Inventory

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

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, we record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three and six months ended June 30, 2013 and 2012.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three and six months ended June 30, 2013 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.

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

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

Intangibles - Goodwill and Other

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

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

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

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

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

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

Debt Issue Costs

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

Debt issue costs, net of accumulated amortization, totaled $515,435 and $532,335 at June 30, 2013 and December 31, 2012, respectively. Accumulated amortization was $160,545 and $143,645 at June 30, 2013 and December 31, 2012, respectively, and is being amortized over the life of the Refinery Note. For the three and six months ended June 30, 2013, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. For the three and six months ended June 30, 2012, amortization expense, which is included in interest expense, was $8,450 and $16,900, respectively. See “Note (14) Notes Payable” and “Note (17) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

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

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

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

Income Taxes

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

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards. See “Note (20) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Treasury Stock

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

Business Combinations

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

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

Reclassification

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

New Pronouncements Issued but Not Yet Effective

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

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17. Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Long Term Debt

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

	June 30,		December 31,
	2013		2012
Refinery Note	$	9,256,114	$	9,298,183
Construction and Funding Agreement		8,850,775		5,206,175
Notre Dame Debt		1,300,000		1,300,000
Captial Leases		-		2,119
		19,406,889		15,806,477
Less: Current portion of long-term debt		10,741,114		1,816,960
	$	8,665,775	$	13,989,517

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10. Inventories

6 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventory balances consisted of the following:

	June 30,		December 31,
	2013		2012
Low-sulfur diesel	$	1,054,402	$	397,240
Naphtha		1,510,195		1,562,055
Atmospheric gas oil		750,476		322,356
Crude		19,041		19,041
	$	3,334,114	$	2,300,692

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products and Crude Oil Inventory Risk Management

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

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

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

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

As of June 30, 2013, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

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

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

		Fair Value
		June 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$	79,200	$	(136,100	)

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

		Gain (Loss) Recognized
		Three Months Ended June 30,				Six Months Ended June 30,
Derivatives	Statements of Operations Location	2013		2012		2013			2012
Commodity contracts	Cost of refined products sold	$	55,350	$	-	$	(33,141	)	$	-

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1. Organization

6 Months Ended

Jun. 30, 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. Our primary asset is a fifty-six (56) acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”). As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (4) Business Segment Information” for further discussion of our business segments.

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

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

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

·   Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations);

·   Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);

·   Blue Dolphin Services Co., a Texas corporation (administrative services);

·   Blue Dolphin Exploration Company, a Delaware corporation (exploration and production investments) (“BDEX”); and

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

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6. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 2) (Commodity Contracts [Member], USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Commodity Contracts [Member]
Cost of refined products sold	$ 55,350		$ (33,141)

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4. Business Segment Information (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting [Abstract]
Amortization expense	$ 143,645		$ 143,645
Cost of refined products sold realized loss	212,001		248,441
Cost of refined products sold unrealized gain	$ 79,200		$ 215,300

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6. Refined Products Inventory Risk Management (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

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

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

		Fair Value
		June 30,		December 31,
Asset Derivatives	Balance Sheets Location	2013		2012
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$	79,200	$	(136,100	)

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

		Gain (Loss) Recognized
		Three Months Ended June 30,				Six Months Ended June 30,
Derivatives	Statements of Operations Location	2013		2012		2013			2012
Commodity contracts	Cost of refined products sold	$	55,350	$	-	$	(33,141	)	$	-

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18. Leases (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Leases Details Narrative
Rent expense	$ 25,161	$ 28,344	$ 51,221	$ 51,221

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13. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Payables and Accruals [Abstract]
Expense for service	$ 2,724,644	$ 2,239,914	$ 5,469,853	$ 3,302,665
Accounts payable, related party	$ 2,507,422		$ 2,507,422		$ 1,594,021

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13. Accounts Payable, Related Party

6 Months Ended

Jun. 30, 2013

Payables and Accruals [Abstract]

Accounts Payable, Related Party

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

Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement 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 June 30, 2013 and 2012 were $2,724,644 (approximately $2.70 per barrel) and $2,239,914 (approximately $2.85 per barrel). Aggregate amounts expensed for Services at the Nixon Facility for the six months ended June 30, 2013 and 2012 were $5,469,853 (approximately $2.75 per barrel) and $3,302,665 (approximately $2.80 per barrel). At June 30, 2013 and December 31, 2012, the amounts outstanding to LEH were $2,507,422 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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9. Deposits

6 Months Ended

Jun. 30, 2013

Banking and Thrift [Abstract]

Deposits

Deposit balances consisted of the following:

	June 30,		December 31,
	2013		2012
Utility deposits	$	31,250	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		792,000
Purchase option deposits		283,421		283,421
Rent deposits		9,463		-
	$	1,240,660	$	1,236,447

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20. Income Taxes (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Income Taxes Details Narrative
Income tax expense	$ 0	$ 17,419	$ 0	$ (13,144)

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16. Asset Retirement Obligations

6 Months Ended

Jun. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Refinery and Facilities

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

Oil and Gas Properties and Pipelines and Facilities Assets

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

Asset retirment obligations at December 31, 2012	$	921,260
Liabilities settled		(8,244	)
Accretion expense		56,341
		969,357
Less:  current portion of asset retirement obligations		85,347
Asset retirement obligations, long-term balance
at June 30, 2013	$	884,010

For the three months ended June 30, 2013, we recognized $23,901 in abandonment expense for AROs associated with our High Island A-7 oil and gas property. Abandonment costs for High Island A-7, which exceeded the ARO liability, were recognized as a loss during the period. We will record additional plugging and abandonment costs for High Island A-7 as information becomes available from the operator, Apache Corp., to substantiate actual and/or probable costs.

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14. Note Payable

6 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Note Payable

Notes payable at June 30, 2013 and December 31, 2012 was $46,136 and $43,941, respectively.

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 $34,865 and $39,866 at June 30, 2013 and December 31, 2012, respectively. The unsecured note, which bears interest at a base rate of 10% and a default rate of 18%, was originally due in January 2012. The due date has been extended to December 2013. 

Short-Term Capital Leases. The balance on short-term notes under capital lease agreements was $11,271 and $0 at June 30, 2013 and December 31, 2012, respectively. In January 2013 we acquired a pressure washer under an interest-free, short-term capital lease. Capital leases totaling $1,250, which were classified as long-term debt at December 31, 2012, have been re-classified to short-term debt at June 30, 2013 as they mature at various dates through February 2014. These capital leases have interest rates ranging from 0% to 13.04%. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets. The assets are amortized over the lower of their related lease terms or their estimated productive lives.

The balance on a short-term note related to previously owned trucks for use at the Nixon Facility was $0 and $4,075 at June 30, 2013 and December 31, 2012, respectively. The unsecured note bore interest at 5%.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Aug. 13, 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	Jun. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,571,629
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2013

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15. Accrued Expenses and Other Current Liabilities

6 Months Ended

Jun. 30, 2013

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	June 30,		December 31,
	2013		2012
Excise taxes	$	283,640	$	292,303
Turnaround expenses		63,646		-
Transportation		-		69,551
Other payable		252,199		134,501
Property taxes		27,000		-
Insurance		22,440		-
Unrealized hedging loss		-		136,100
Unearned revenue		65,000		92,783
	$	713,925	$	725,238

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15. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Accrued Expenses And Other Current Liabilities Details
Excise taxes	$ 283,640	$ 292,303
Turnaround expenses	63,646
Transportation		69,551
Other payable	252,199
Property taxes	27,000
Insurance	22,440
Unrealized hedging loss		136,100
Unearned revenue	65,000	92,783
Accrued Expenses and Other Current Liabilities, Net	$ 713,925	$ 725,238

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14. Note Payable (Details Narrative) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Short-term note	$ 34,865	$ 39,866
Note payable	46,136	43,941
Short-term notes under capital lease agreements	11,271	0
Balance on a short-term note related to previously owned trucks	$ 0	$ 4,075