10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended:  March 31, 2014

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

For the transition period from _____________ to_____________

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

(713) 568-4725

(Registrant’s telephone number, including area code)

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

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

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

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

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

Yes o No þ

Number of shares of common stock, par value $0.01 per share outstanding as of May 15, 2014:  10,446,218

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

FORM 10-Q REPORT INDEX

PART I	FINANCIAL INFORMATION	1
ITEM 1.	FINANCIAL STATEMENTS	1
	Consolidated Balance Sheets (Unaudited)	1
	Consolidated Statements of Operations (Unaudited)	2
	Consolidated Statements of Cash Flows (Unaudited)	3
	Notes to Consolidated Financial Statements (Unaudited)	4
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40
ITEM 4.	CONTROLS AND PROCEDURES	40
PART II	OTHER INFORMATION	41
ITEM 1.	LEGAL PROCEEDINGS	41
ITEM 1A.	RISK FACTORS	41
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	42
ITEM 4	MINE SAFETY DISCLOSURES	42
ITEM 5.	OTHER INFORMATION	42
ITEM 6.	EXHIBITS	42
SIGNATURES		43

Remainder of Page Intentionally Left Blank

PART I                         FINANCIAL INFORMATION

  ITEM 1.  FINANCIAL STATEMENTS

Blue Dolphin Energy Company & Subsidiaries

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	295,877		$	434,717
Restricted cash		1,003,124			327,388
Accounts receivable		9,749,014			13,487,106
Prepaid expenses and other current assets		263,028			333,683
Deposits		819,213			1,219,660
Inventory		4,396,893			4,686,399
Total current assets		16,527,149			20,488,953
Total property and equipment, net		36,358,219			36,388,666
Surety bonds		850,000			-
Debt issue costs, net		490,086			498,536
Trade name		303,346			303,346
TOTAL ASSETS	$	54,528,800		$	57,679,501
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	15,863,920		$	20,783,541
Accounts payable, related party		3,620,647			3,659,340
Notes payable		-			11,884
Asset retirement obligations, current portion		108,272			107,388
Accrued expenses and other current liabilities		1,968,318			1,600,444
Interest payable, current portion		41,205			40,272
Long-term debt, current portion		1,000,922			2,215,918
Total current liabilities		22,603,284			28,418,787
Long-term liabilities:
Asset retirement obligations, net of current portion		1,841,044			1,490,273
Deferred revenues and expenses		821,187			-
Long-term debt, net of current portion		9,837,229			13,889,349
Long-term interest payable, net of current portion		1,118,072			1,767,381
Total long-term liabilities		13,617,532			17,147,003
TOTAL LIABILITIES		36,220,816			45,565,790
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,580,973
shares issued at March 31, 2014 and December 31, 2013)		105,810			105,810
Additional paid-in capital		36,623,965			36,623,965
Accumulated deficit		(17,621,791	)		(23,816,064	)
Treasury stock, 150,000 shares and 0 shares, respectively, at cost		(800,000	)		(800,000	)
Total stockholders' equity		18,307,984			12,113,711
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	54,528,800		$	57,679,501

See accompanying notes to consolidated financial statements.

1

Blue Dolphin Energy Company & Subsidiaries

Consolidated Statements of Operations (Unaudited)

	Three Months Ended March 31,
	2014			2013
REVENUE FROM OPERATIONS
Refined product sales	$	120,376,151		$	109,171,507
Pipeline operations		54,031			73,148
Total revenue from operations		120,430,182			109,244,655
COST OF OPERATIONS
Cost of refined products sold		110,415,607			106,322,661
Refinery operating expenses		2,955,019			2,745,209
Pipeline operating expenses		27,729			45,371
Lease operating expenses		7,176			26,901
General and administrative expenses		369,484			484,564
Depletion, depreciation and amortization		390,605			328,788
Abandonment expense		-			27,451
Accretion expense		50,802			25,163
Total cost of operations		114,216,422			110,006,108
Income (loss) from operations		6,213,760			(761,453	)
OTHER INCOME (EXPENSE)
Net tank rental and easement revenue		407,516			278,350
Interest and other income		29,220			835
Interest expense		(253,800	)		(281,063	)
Total other income (expense)		182,936			(1,878	)
Income (loss) before income taxes		6,396,696			(763,331	)
Income tax expense, current		(202,423	)		-
Net income (loss)	$	6,194,273		$	(763,331	)
Income (loss) per common share
Basic	$	0.59		$	(0.07	)
Diluted	$	0.59		$	(0.07	)
Weighted average number of common shares outstanding:
Basic		10,430,973			10,510,334
Diluted		10,430,973			10,510,334

See accompanying notes to consolidated financial statements.

2

Blue Dolphin Energy Company & Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2014			2013
OPERATING ACTIVITIES
Net income (loss)	$	6,194,273		$	(763,331	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization		390,605			328,788
Unrealized loss on derivatives		127,100			52,050
Amortization of debt issue costs		8,450			8,450
Amortization of intangible assets		-			9,463
Accretion expense		50,802			25,163
Abandonment costs incurred		-			27,451
Common stock issued for services		-			50,000
Changes in operating assets and liabilities
Restricted cash		(675,736	)		62,245
Accounts receivable		3,738,092			4,087,965
Prepaid expenses and other current assets		70,655			19,355
Deposits and other assets		(449,553	)		(9,463	)
Inventory		289,506			(1,489,100	)
Accounts payable, accrued expenses and other liabilities		(4,506,163	)		(2,739,371	)
Accounts payable, related party		(38,693	)		584,040
Net cash provided by operating activities		5,199,338			253,705
INVESTING ACTIVITIES
Capital expenditures		(59,178	)		(530,226	)
Net cash used in investing activities		(59,178	)		(530,226	)
FINANCING ACTIVITIES
Payments on long-term debt		(5,267,116	)		(60,876	)
Proceeds from notes payable		-			15,032
Payments on notes payable		(11,884	)		(10,472	)
Net cash used in financing activities		(5,279,000	)		(56,316	)
Net decrease in cash and cash equivalents		(138,840	)		(332,837	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		434,717			420,896
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	295,877		$	88,059
Supplemental Information:
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received	$	-		$	800,000
Surety bond funded by seller of pipeline interest holder	$	850,000		$	-
Non-cash investing and financing activities:
New asset retirement obligations	$	300,980		$	-
Accrued services payable converted to common stock	$	-		$	50,000
Interest paid	$	902,176		$	232,577

See accompanying notes to consolidated financial statements.

3

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)
(1)	Organization

Nature of Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company.  We are primarily an independent refiner and marketer of petroleum products.  Our primary operating asset is a 56-acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  Operations at the Nixon Facility also involve the storage and terminaling of petroleum under third-party lease agreements. We also own and operate pipeline assets and have leasehold interests in oil and gas properties, which are considered non-core to our business. See “Note (4) Business Segment Information” of this report for further discussion of our business segments.

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

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

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

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

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

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

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

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

Operating Risks

We had cash and cash equivalents of $295,877 and $434,717 at March 31, 2014 and December 31, 2013, respectively. As of March 31, 2014, we were in violation of certain financial covenants in a loan agreement dated September 29, 2008 (the “Loan Agreement”) by and between LE and First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000 (the “Refinery Note”).  In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”).  We are currently making our scheduled payments in accordance with the terms and conditions of the Loan Agreement and, as of December 31, 2013, we obtained a waiver for these financial covenants effective through December 31, 2014.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

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

We believe that our operational strategy, including our introduction and production of jet fuel beginning in the third quarter of 2013 and the continued refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility, will be sufficient to support our operations over the next twelve months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

4

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(2) Basis of Presentation

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

 (3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and notes are representations of 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 our consolidated financial statements.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe 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 $295,877 and $434,717 at March 31, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted cash was $1,003,124 and $327,388 at March 31, 2014 and December 31, 2013, respectively. These amounts primarily relate to a payment reserve account required under the Refinery Note.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $765,996 and $77,388 at March 31, 2014 and December 31, 2013, respectively.

For the three months ended March 31, 2014, we had 4 customers that accounted for approximately 87% of our refined petroleum product sales.  These 4 customers represented approximately $7.4 million in accounts receivable at March 31, 2014.  For the three months ended March 31, 2013, we had 4 customers that accounted for approximately 81% of our refined petroleum product sales.  These 4 customers represented approximately $7.5 million in accounts receivable at March 31, 2013.

5

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Inventory

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

Price-Risk Management Activities

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

Property and Equipment

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included in the Management Agreement and covered by LEH (see “Note (9) Accounts Payable Related Party” and “Note (24) Subsequent Events” of this report for additional disclosures related to the Management Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2014 and 2013.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three months ended March 31, 2014 and 2013 due to leases being relinquished and fields being shut-in by operators.

Pipelines and Facilities Assets. 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 – Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

6

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Debt Issue Costs

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

Debt issue costs, net of accumulated amortization, totaled $490,086 and $498,536 at March 31, 2014 and December 31, 2013, respectively.  Accumulated amortization was $185,894 and $177,445 at March 31, 2014 and December 31, 2013, respectively.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2014 and 2013.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

Deferred Revenue.  On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”) and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”), whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed security bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  We recorded $850,000 of deferred revenue in connection with the WBI transaction. Deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the Pipeline Assets.   See “Note (23) WBI Transaction” of this report for additional disclosures related to WBI.

Tank Storage Rental Revenue. Revenue from tank storage rental and land easement agreements are recorded monthly in accordance with the terms of the related lease agreement and included as other income.  The lessee is invoiced monthly for the amount of rent due for the related period.

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.

7

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (18) Income Taxes” of this report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

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

8

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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

Stock-Based Compensation

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

Treasury Stock

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

Business Combinations

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

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

Reclassification

We have reclassified certain prior year amounts to conform to our 2014 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.

9

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(4) Business Segment Information

We have two reportable business segments: (i) “Refinery Operations” and (ii) “Pipeline Transportation.”  Business activities related to our “Refinery Operations” business segment are conducted at the Nixon Facility.  Business activities related to our “Pipeline Transportation” business segment are primarily conducted in the U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.

Segment financials for the three months ended March 31, 2014 (and at March 31, 2014) were as follows:

	Three Months Ended March 31, 2014
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	120,376,151		$	54,031		$	-		$	120,430,182
Operation cost(1)(2)(3)		(113,368,578	)		(122,510	)		(334,729	)		(113,825,817	)
Other non-interest income		282,516			152,697			-			435,213
EBITDA	$	7,290,089		$	84,218		$	(334,729	)
Depletion, depreciation and
amortization											(390,605	)
Other expense, net											(252,277	)
Income before income taxes										$	6,396,696
Capital expenditures	$	59,178		$	-		$	-		$	59,178
Identifiable assets(4)	$	50,797,212		$	3,201,220		$	530,368		$	54,528,800

(1)	“Refinery operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis. Cost of refined products sold within operation cost includes a realized loss of $54,469 and an unrealized loss of $127,100.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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10

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended March 31, 2013
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	109,171,507		$	73,148		$	-		$	109,244,655
Operation cost(1)(2)(3)		(109,063,677	)		(154,498	)		(459,145	)		(109,677,320	)
Other non-interest income		278,350			-			-			278,350
EBITDA	$	386,180		$	(81,350	)	$	(459,145	)
Depletion, depreciation and
amortization											(328,788	)
Other expense, net											(280,228	)
Loss before income taxes										$	(763,331	)
Capital expenditures	$	530,226		$	-		$	-		$	530,226
Identifiable assets(4)	$	50,131,322		$	1,662,384		$	967,906		$	52,761,612

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis.  Cost of refined products sold within operation cost includes a realized loss of $36,440 and an unrealized loss of $52,050.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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11

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(5) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	March 31,		December 31,
	2014		2013
Prepaid insurance	$	138,562	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		11,250		15,000
Prepaid taxes		9,216		9,216
Unrealized hedging gains		-		6,950
	$	263,028	$	333,683

(6) Deposits

Deposit balances consisted of the following:

	March 31,		December 31,
	2014		2013
Utility deposits	$	17,750	$	10,250
Equipment deposits		-		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	819,213	$	1,219,660

(7) Inventory

Inventory balances consisted of the following:

	March 31,		December 31,
	2014		2013
Low-sulfur diesel	$	231,756	$	1,813,662
Naphtha		670,156		804,490
Atmospheric gas oil		527,430		575,919
Jet fuel		2,852,755		1,444,399
LPG mix		95,755		28,888
Crude		19,041		19,041
	$	4,396,893	$	4,686,399

12

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(8) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	March 31,		December 31,
	2014		2013
Refinery and facilities	$	35,852,928	$	35,852,928
Pipelines and facilities		2,127,207		1,826,226
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		567,813		567,813
		39,451,348		39,150,367
Less:  Accumulated depletion, depreciation and amortization		3,407,318		3,016,713
		36,044,030		36,133,654
Construction in Progress		314,189		255,012
Property, Plant and Equipment, Net	$	36,358,219	$	36,388,666

(9) Accounts Payable, Related Party

LEH, which owns approximately 81% of our outstanding common stock, par value $0.01 per share (the “Common Stock”), manages all of our subsidiaries and operates all of our assets, including the Nixon Facility, (the “Services”) pursuant to a Management Agreement dated February 15, 2012 (the “Management Agreement”).  Jonathan Carroll, Chief Executive Officer and President of Blue Dolphin, is the majority owner of LEH.

With respect to the Nixon Facility, the Management Agreement represents, in effect, an operating agreement that covers all refinery operating expenses with the exception of capital expenditures.  Pursuant to the Management Agreement, for management and operation of the Nixon Facility, LEH receives as compensation: (i) weekly payments from GEL not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the 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. For all other assets, LEH is reimbursed at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month.

The Management Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement, which has an initial term of three years and successive one-year renewals until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice, (b) August 12, 2015, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended March 31, 2014 and 2013 were $2,955,019 (approximately $2.71 per barrel of throughput) and $2,745,209 (approximately $2.80 per barrel of throughput). At March 31, 2014 and December 31, 2013, the amounts outstanding to LEH to fund our working capital requirements were $3,620,647 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.

See “Note (24) Subsequent Events” on this report for further disclosures related to the Management Agreement.

13

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

 (10) Notes Payable

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

	March 31,		December 31,
	2014		2013
Short-Term Note for Financing Costs	$	-	$	9,379
Short-Term Captial Leases		-		2,505
	$	-	$	11,884

Short-Term Note for Financing Services.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing services was $0 and $9,379 at March 31, 2014 and December 31, 2013, respectively.  The unsecured note, which bore interest at a base rate of 10% and a default rate of 18%, was paid off during the first quarter of 2014. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $0 and $2,505 at March 31, 2014 and December 31, 2013, respectively.  These capital leases, which had interest rates ranging from 0% to 13.04%, were paid off during the first quarter of 2014.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

 (11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following: 

	March 31,		December 31,
	2014		2013
Excise and income taxes payable	$	1,037,001	$	688,754
Transportation and inspection		138,000		100,000
Property taxes		10,426		-
Insurance		63,238		-
Unrealized hedging loss		120,150		-
Unearned revenue		112,505		302,505
Board of director fees payable		325,000		240,000
Other payable		161,998		269,185
	$	1,968,318	$	1,600,444

(12) Asset Retirement Obligations

Refinery and Facilities

Management has concluded that there is no legal or contractual obligation to dismantle or remove the Nixon Refinery and related facilities 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.

14

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Pipelines and Facilities Assets and Oil and Gas Properties

We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Effective December 31, 2013, we updated our estimates in computing the estimated ARO for the abandonment in place of our pipelines and an associated platform.

The following provides a roll-forward of our AROs:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(127	)
Accretion expense		50,802
		1,949,316
Less:  current portion of asset retirement obligations		108,272
Asset retirement obligations, long-term balance
at March 31, 2014	$	1,841,044

On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. Once plugging and abandonment work has been completed, the collateral will be released to BDPL.  The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of the pipelines.   See “Note (23) WBI Transaction” of this report for additional disclosures related to WBI.

For the three months ended March 31, 2014, we recognized $0 in abandonment expense related to our oil and gas properties.  For the three months ended March 31, 2013, we recognized $27,451 in abandonment expense for AROs associated with our HI-A7 oil and gas property. We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

(13) Long-Term Debt

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

	March 31,		December 31,
	2014		2013
Refinery Note	$	8,958,892	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		579,259		5,747,330
		10,838,151		16,105,267
Less: Current portion of long-term debt		1,000,922		2,215,918
	$	9,837,229	$	13,889,349

Refinery Note.   The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at March 31, 2014) and has a maturity date of October 1, 2028 (the “Maturity Date”).  LE’s obligations under the Refinery Note are secured by a Deed of Trust (the “Deed of Trust”) of even date with the Loan Agreement.  The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Loan Agreement, the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE.  The principal balance outstanding on the Refinery Note was $8,958,892 and $9,057,937 at March 31, 2014 and December 31, 2013, respectively.  Interest was accrued on the Refinery Note in the amount of $41,205 and $40,132 at March 31, 2014 and December 31, 2013, respectively.  See “Note (1) Organization – Operating Risks” of this report for additional disclosures related to the Refinery Note.

15

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

The Loan Agreement has two financial covenants relating to a current ratio and debt-to-worth.  As of March 31, 2014, we were in violation of the current ratio covenant. However, as of December 31, 2013, we obtained a waiver related to the financial covenants effective through December 31, 2014.   We expect to be in compliance with the financial covenants upon termination of the waiver period.  Accordingly, the Refinery Note has been classified as long-term on our consolidated balance sheets.

In October 2011, the Refinery Loan Documents were acquired by AFNB.  On 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.  Payments under the Construction and Funding Agreement began 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 $579,259 and $5,747,330 at March 31, 2014 and December 31, 2013, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $0 and $700,597 at March 31, 2014 and December 31, 2013, respectively.  There are no financial covenants associated with this obligation.

See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to amendments and/or modifications to the Crude Supply Agreement, Construction and Funding Agreement and Joint Marketing Agreement.

Notre Dame Debt.  LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8,000,000, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt accrues interest at a rate of 16% and is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  The principal balance outstanding on the Notre Dame Debt was $1,300,000 at March 31, 2014 and December 31, 2013.  Interest was accrued on the Notre Dame Debt in the amount of $1,118,072 and $1,066,784 at March 31, 2014 and December 31, 2013, respectively.  There are no financial covenants associated with the Notre Dame Debt.  The due date of the Notre Dame Debt was extended to July 1, 2015.

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

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

Pursuant to a First Amendment to Promissory Note made effective July 1, 2013, the Notre Dame Debt was amended as follows:  (i) the annual interest rate on the unpaid balance was set to 16% and (ii) the final maturity became July 1, 2015.

(14) Stock Options

Blue Dolphin’s Board established a 2000 Stock Incentive Plan (the “Plan”) on April 14, 2000 and the Plan was subsequently approved by Blue Dolphin’s stockholders on May 18, 2000.  The Plan offered incentive awards to employees, including officers (whether or not they are directors), consultants and non-employee directors. The Plan has undergone several amendments, as follows:  (i) Amendment No. 1 -- 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, (ii) Amendment No. 2 -- 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, (iii) Amendment No. 3 -- 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, (iv) Amendment No. 4 -- 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.

16

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Although the Compensation Committee of the Board of Directors (the “Board”) approved continuation of the Plan following Blue Dolphin’s reverse merger with LE in 2012, pursuant to the Management Agreement, all employees of Blue Dolphin became employees of LEH effective February 15, 2012.  As a result, with the exception of options outstanding for Ivar Siem, options outstanding for Blue Dolphin employees were cancelled 90 days following the effective date of the Management Agreement.  All of Mr. Siem’s options expired in October 2013.

For the three months ended March 31, 2014 and 2013 there were no stock options granted under the Plan.  For the three months ended March 31, 2014 and 2013, we recognized no compensation expense for vested stock options.

At March 31, 2014, there were no options outstanding, no options exercisable or no shares of common stock reserved for issuance under the Plan.  As of March 31, 2014, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

(15) Treasury Stock

During the three months ended March 31, 2013, BDEX completed a non-cash transaction to dispose of its 7% undivided working interest in an oil property located in Indonesia (“Indonesia”) pursuant to a Sale and Purchase Agreement with Blue Sky Langsa, Ltd. (“Blue Sky”) dated November 6, 2012.   Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of Common Stock, which represented a recovery of a significant portion of the 342,857 shares of Common Stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  As of March 31, 2014 and December 31, 2013, we had 150,000 shares of treasury stock.

(16) Concentration of Risk

Significant Customers.  Customers of our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area).  We have bulk term contracts, including month-to-month, six month and up to five year terms, in place with most of our customers.  Certain of our contracts require us to sell fixed quantities and/or minimum quantities and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products.  See “Note (2) Basis of Presentation” of this report for additional disclosures related to significant customers.

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

	Three Months Ended March 31,
	2014			2013
Low-sulfur diesel		32.2	%		49.7	%
Naphtha		23.9	%		26.0	%
Atmospheric gas oil		27.1	%		24.1	%
LPG mix		0.1	%		0.0	%
Reduced crude		0.0	%		0.2	%
Jet fuel		16.7	%		0.0	%
		100.0	%		100.0	%

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable refined petroleum product.  Jet fuel is produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream.  Production of jet fuel, which is considered a higher value product, significantly upgrades the value of the naphtha component.

17

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement.  On October 30, 2013, LE entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam (the “October 2013 Letter Agreement”), effective October 24, 2013.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

(17) Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. The current minimum payment is $9,685 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 March 31, 2014 and 2013, rent expense for the office lease was $25,829 and $29,041, respectively.

(18) Income Taxes

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

Section 382 of the Internal Revenue Code imposes a limitation on the use of Blue Dolphin’s NOLs generated prior to the reverse merger.  The amount of NOLs subject to such limitation is approximately $18.8 million, of which approximately $1.9 million is projected to be utilized during the three months ended March 31, 2014.  NOLs generated subsequent to the reverse merger through December 31, 2013 of approximately $11.7 million are not subject to any such limitation. Approximately $4.1 million of the post-merger NOLs are projected to be utilized during the three months ended March 31, 2014.  For the three months ended March 31, 2014, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended March 31, 2014 and 2013, income tax expense was $202,423 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $120,552 was the result of a valuation allowance on the alternative minimum tax deferred tax asset.  The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.  At March 31, 2014, we accrued $81,871 in TMT.

(19) Earnings Per Share

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

	Three Months Ended
	March 31,
	2014		2013
Net income (loss)	$	6,194,273	$	(763,331	)
Basic and diluted income (loss) per share	$	0.59	$	(0.07	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,430,973		10,510,334

18

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

Diluted EPS is computed by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2014 excluded stock options as there were no stock options outstanding under the Plan.  Diluted EPS for the three months ended March 31, 2013 excludes stock options as they would be anti-dilutive

(20) Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at March 31, 2014 and December 31, 2013 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at March 31, 2014 and December 31, 2013 was $10,838,151 and $16,117,151, respectively. The fair value of our debt was determined using a Level 3 hierarchy.

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2014 and the basis for that measurement:

				Fair Value Measurement at March 31, 2014 Using
Financial assets:	Carrying Value at March 31, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(120,150	)	$	(120,150	)	$	-	$	-

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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

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

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

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

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

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

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

As of March 31, 2014, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

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

20

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

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

		Fair Value
		March 31,	December 31,
Asset Derivatives	Balance Sheets Location	2014	2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$      (120,150)	$            6,950

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2014 and 2013: 

		Loss Recognized
		Three Months Ended
		March 31,
Derivatives	Statements of Operations Location	2014		2013
Commodity contracts	Cost of refined products sold	$	127,100	$	52,050

(22) Commitments and Contingencies

Management Agreement

See “Note (9) Accounts Payable, Related Party” and “Note (24) Subsequent Events” 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. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

● Construction and Funding Agreement.  Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam 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:  (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.

21

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility.  All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement will constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.

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

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

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

(c)

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

(d)

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

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

22

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances.  For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above.  The Joint Marketing Agreement had an initial term of three years expiring on August 12, 2014.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

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

(a) In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our 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 March 31, 2014, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $579,259.  As of March 31, 2014, 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 $0.

Sales Commitments

We have a sales commitment with a significant customer to sell Non-Road, Locomotive and Marine Diesel fuel (“NRLM”) at a market based price less a fixed margin.  The agreement allows the customer to purchase 80% of the NRLM that we produce and requires us to sell a minimum of 2,380,000 barrels through December 31, 2017. We have sold more than 2,000,000 barrels to date under this agreement.  Subsequent to the balance sheet date, we amended the agreement with the customer to begin selling oil based mud blend stock effective June 1, 2014, instead of NRLM, at a market based price less a fixed margin.  Under the amended agreement, the customer must purchase 80% of the oil based mud blend stock that we produce or 100% if our monthly production is less than 2,625 barrels per day. We plan to produce the oil based mud blend stock as of June 1, 2014 to meet this contractual requirement.

Master Easement Agreement - BDPL and FLNG Land

On December 11, 2013 (the “Effective Date”), BDPL and FLNG Land, II, Inc., a Delaware corporation (“FLNG”), entered into a Master Easement Agreement (the “Master Easement Agreement”) whereby BDPL is providing FLNG with: (i) free and uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG (the “Access Easement”) and (ii) a perpetual permanent pipeline easement and right of way across certain property of BDPL to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”).  As initial consideration for the grant of the Easements, FLNG paid BDPL the sum of $250,000 (the “Initial Payment”) on the Effective Date.  FLNG has the option to terminate the Master Easement Agreement within ten (10) months of the Effective Date.  If FLNG commences improvements within the Access Easement or commences construction within the Pipeline Easement (the “Commencement Date”), FLNG shall make a second payment of $250,000 to BDPL (the “Second Payment”).

23

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

If FLNG elects to make the Second Payment, then on or before the first anniversary of the Commencement Date through the greater of: (i) the fifth anniversary of said date or (ii) the date on which the third of FLNG’s planned liquefaction pre-treatment train facilities has reached completion sufficient to permit its start-up and initial operational testing, FLNG shall make annual payments of $500,000 (“the Annual Payments”) to BDPL. Upon delivery of the Initial Payment, Second Payment, and each of the remaining Annual Payments, the Easements shall be fully paid for by FLNG.  One year after the final Annual Payment is made, FLNG will begin paying to BDPL  annual payments of $10,000 for so long as FLNG desires to use the Access Easement.  The terms of the Easements are perpetual, unless terminated by FLNG prior to the Commencement Date or if FLNG elects to permanently cease use of the Access Easement or Pipeline Easement, as applicable.

Supplemental Pipeline Bonds

On February 5, 2014, WBI and BDPL entered into Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  The bond increased the collateral held by a surety company relating to supplemental pipeline bonds issued on behalf of BDPL to satisfy the bonding requirements of the Bureau of Ocean Energy Management.  These supplemental pipeline bonds are intended to secure the performance of BDPL’s plugging and abandonment obligations with respect to pipeline segments in federal waters of the U.S. Gulf of Mexico.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

LTRI Option

In June 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Texas Refinery I, LLC (“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.  The LTRI Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LTRI.

LED Option

In connection with the reverse merger with LE in 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Energy Development, LLC (“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.   The LED Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LED.

Legal Matters

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

Health, Safety and Environmental Matters

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

24

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

(23) WBI Transaction

On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

We recorded $850,000 of deferred revenue in connection with the WBI transaction. Deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the Pipeline Assets. The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, whichrepresents the fair value of the liability, and increased accretion expense throughout the remaining useful life of the pipelines.

(24) Subsequent Events

On May 2, 2014, LRM entered into a Loan and Security Agreement (the “Loan and Security Agreement”) with Sovereign Bank, a Texas state bank, providing for a credit facility to be made to LRM in the aggregate sum of $2.0 million (the “Credit Facility”).  The proceeds of the Credit Facility will be used primarily to finance cost associated with refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility.  The Credit Facility carries a twelve month term and a fixed interest rate of 6.00%.  The Credit Facility contains representations and warranties, affirmative, restrictive, and financial covenants, and events of default which are customary for credit facilities of this type.  The Credit Facility is secured by certain assets of LRM, as well as assets of LEH and its affiliates. In addition, the repayment of funds borrowed and interest accrued under the Credit Facility is personally guaranteed by Jonathan Carroll, Chief Executive Officer and President of Blue Dolphin and majority owner of LEH.

On May 12, 2014, the Management Agreement was amended by: (i) extending the term to August 12, 2015, and (ii) changing the name of the agreement from “Management Agreement” to “Operating Agreement.”  All references to the Management Agreement herein shall mean the “Operating Agreement.”

Remainder of Page Intentionally Left Blank

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

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

Forward Looking Statements

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

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

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

● changes in the general economic conditions;

● changes in the underlying demand for our products;

● 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 continued financing, sourcing of crude oil inventory and marketing of our refined petroleum products;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

● competition from larger companies;

● infrastructure limitations;

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

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

● retention of key personnel;

● insurance coverage that may be inadequate or expensive;

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

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

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

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

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

Company Overview

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

Refinery Operations

Our primary business is the refining of crude oil and condensate into marketable finished and intermediate products at the Nixon Facility, which has a current operating capacity of approximately 15,000 barrels (“bbls”) per day (“bpd”). The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, jet fuel treater, approximately 120,000 bbls of crude oil storage capacity, approximately 148,000 bbls of refined product storage capacity and related loading and unloading facilities and utilities.

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

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Pipeline Transportation

Our pipeline transportation operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines in the U.S. Gulf of Mexico. Producers and shippers are charged a fee based on anticipated throughput volumes.  Our pipeline transportation operations represented less than 1% of total revenue for the three months ended March 31, 2014 and 2013.

Oil and Gas Exploration and Production

Our oil and gas exploration and production assets, which include leasehold interests in properties in the U.S. Gulf of Mexico, were uneconomic for the three months ended March 31, 2014 and 2013 as a result of leases being relinquished and fields being shut-in by operators. Our oil and gas exploration and production operations represented less than 1% of total revenue for the three months ended March 31, 2014 and 2013.

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Owned and Leased Assets

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

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

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

Options to Purchase Assets

 LTRI Option – In June 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Texas Refinery I, LLC (“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.  The LTRI Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LTRI.

●    LED Option – In connection with the LE Acquisition, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Energy Development, LLC (“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.   The LED Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LED.

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Key Operating Statistics

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

	Three Months Ended March 31,
	2014	2013
Nixon Facility
Operating days	90	85
Total refinery throughput(1)
bbls	1,092,007	978,805
bpd	12,133	11,515
Capacity utilization rate	81%	77%
Total refinery production
bbls	1,073,638	958,306
bpd	11,929	11,274
Capacity utilization rate	80%	75%

_____________________________

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

Major Influences on Results of Operations

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

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

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

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

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

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Relationship with Genesis

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

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

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

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

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, an affiliate of Genesis, is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

● Construction and Funding Agreement.  Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam 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:  (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.   In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility.  All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement will constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.

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

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

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

(c)

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

(d)

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

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

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances.  For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above.  The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

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

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

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(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 March 31, 2014, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $579,259.  As of March 31, 2014, 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 $0.

Results of Operations

Three Months Ended March 31, 2014 (the "Current Period") Compared to Three Months Ended March 31, 2013 (the "Prior Period").

The Nixon Facility, which was refurbished and began operations in February 2012, has been operating for approximately two years.  The Nixon Facility operated for a total of 90 days at 81% of operating capacity during the Current Period. The Nixon Facility operated for a total of 85 days at 77% of operating capacity during the Prior Period.

Summary. For the Current Period, we reported net income of $6,194,273, or an income of $0.59 per share, compared to a net loss of $763,331, or a loss of $0.07 per share, for the Prior Period.  The net income in the Current Period was primarily attributable to improved product mix related to jet fuel production and favorable refining margins.  The Nixon Facility operated for 5 more days and had an increase in both total refinery production and total refinery throughput of approximately 12% in the Current Period compared to the Prior Period.

The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations.  Downtime may result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations.  The Nixon Facility experienced no calendar days of downtime in the Current Period compared to 5 calendar days of downtime in the Prior Period for a scheduled maintenance turnaround.

Total Revenue from Operations. For the Current Period, we had total revenue from operations of $120,430,182 compared to total revenue from operations of $109,244,655 for the Prior Period.   The approximate 10% increase in total revenue from operations was primarily the result of increased total refinery throughput of approximately 12% in the Current Period compared to the Prior Period. Substantially all of our revenue in the Current Period came from refined product sales, which generated revenue of $120,376,151, or more than 99% of total revenue from operations, compared to $109,171,507, or more than 99% of total revenue from operations, in the Prior Period.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $110,415,607 for the Current Period compared to $106,322,661 for the Prior Period.  The nearly 4% increase in cost of refined products sold was primarily the result of an increase in the volume of refined products sold.

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Refinery Operating Expenses. We recorded refinery operating expenses of $2,955,019 in the Current Period, all of which were for services provided to us by LEH to manage and operate Blue Dolphin’s assets pursuant to the Management Agreement with LEH.  For the Prior Period, we recorded refinery operating expenses of $2,745,209.  The more than 7% increase in refinery operating expenses in the Current Period compared to the Prior Period was primarily the result of a 12% increase in total refinery production.  See “Part I, Item 1. Financial Statements - Note (9), Accounts Payable, Related Party” and “Note (24) Subsequent Events” of this report for additional disclosures related to the Management Agreement.

General and Administrative Expenses. We incurred general and administrative expenses of $369,484 in the Current Period compared to $484,564 in the Prior Period.  The nearly 24% decrease in general and administrative expenses in the Current Period compared to the Prior Period was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $390,605 in the Current Period compared to $328,788 in the Prior Period.  The approximate 19% increase in depletion, depreciation and amortization expenses for the Current Period compared to the Prior Period primarily related to depreciable refinery assets placed in service.

Abandonment Expense. We recognized no abandonment expense in the Current Period compared to $27,451 in the Prior Period.  Abandonment expense in the Prior Period primarily related to plugging and abandonment costs associated with our High Island A-7 oil and gas property.  We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

Other Income. We recognized $407,516 in net tank rental and easement revenue in the Current Period compared to $278,350 in the Prior Period.  The more than 46% increase in net tank rental and easement revenue in the Current Period compared to the Prior Period was primarily a result of fees received from FLNG Land, II, Inc., a Delaware corporation (“FLNG”), pursuant to a Master Easement Agreement whereby BDPL is providing FLNG with free and uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG.

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

We have two reportable business segments: (i) “Refinery Operations” and (ii) “Pipeline Transportation.”  Business activities related to our “Refinery Operations” business segment are conducted at the Nixon Facility.  Business activities related to our “Pipeline Transportation” business segment are primarily conducted in the U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.  We have reclassified certain prior year amounts to conform to our 2014 presentation.

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

Following is a reconciliation of EBITDA by business segment for the three months ended March 31, 2014 (and at March 31, 2014) and the three months ended March 31, 2013 (and at March 31, 2013):

	Three Months Ended March 31, 2014
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	120,376,151		$	54,031		$	-		$	120,430,182
Operation cost(1)(2)(3)		(113,368,578	)		(122,510	)		(334,729	)		(113,825,817	)
Other non-interest income		282,516			152,697			-			435,213
EBITDA	$	7,290,089		$	84,218		$	(334,729	)	$	7,039,578
Depletion, depreciation and
amortization											(390,605	)
Other expense, net											(252,277	)
Income before income taxes										$	6,396,696
Capital expenditures	$	59,178		$	-		$	-		$	59,178
Identifiable assets(4)	$	50,797,212		$	3,201,220		$	813,789		$	54,812,221

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis.  Cost of refined products sold within operation cost includes a realized loss of $54,469 and an unrealized loss of $127,100.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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	Three Months Ended March 31, 2013
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	109,171,507		$	73,148		$	-		$	109,244,655
Operation cost(1)(2)(3)		(109,063,677	)		(154,498	)		(459,145	)		(109,677,320	)
Other non-interest income		278,350			-			-			278,350
EBITDA	$	386,180		$	(81,350	)	$	(459,145	)	$	(154,315	)
Depletion, depreciation and
amortization											(328,788	)
Other expense, net											(280,228	)
Loss before income taxes										$	(763,331	)
Capital expenditures	$	530,226		$	-		$	-		$	530,226
Identifiable assets(4)	$	50,131,322		$	1,662,384		$	967,906		$	52,761,612

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis.  Cost of refined products sold within operation cost includes a realized loss of $36,440 and an unrealized loss of $52,050.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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Critical Accounting Policies

Long Lived Assets.

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and included in the Management Agreement and covered by LEH (see “Part I, Item 1. Financial Statements – Note (9) Accounts Payable, Related Party” and “Note (24) Subsequent Events” of this report for additional disclosures related to the Management Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2014 and 2013.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three months ended March 31, 2014 and 2013 due to leases expiring and wells being shut-in by operators.

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

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

Other Intangible Assets. We recognized trade name in connection with our reverse merger with LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2013 following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

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

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

Revenue from tank storage rental and land easement agreements are recorded monthly in accordance with the terms of the related lease agreement and included as other income. The lessee is invoiced monthly for the amount of rent due for the related period.

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

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

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

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

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.

Recently Adopted Accounting Guidance

The guidance issued by the FASB during the three months ended March 31, 2014 is not expected to have a material effect on our consolidated financial statements.

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Liquidity and Capital Resources

Sources and Uses of Cash.

	For Three Months Ended March 31,
	2014			2013
Cash flow from operations
Adjusted income (loss) from continuing operations	$	6,771,230		$	(261,966	)
Change in assets and current liabilities		(1,571,892	)		515,671
Total cash flow from operations		5,199,338			253,705
Cash inflows (outflows)
Payments on long term debt		(5,267,116	)		(60,876	)
Capital expenditures		(59,178	)		(530,226	)
Proceeds from notes payable		-			15,032
Payments on note payble		(11,884	)		(10,472	)
Total cash outflows		(5,338,178	)		(586,542	)
Total change in cash flows	$	(138,840	)	$	(332,837	)

At March 31, 2014, our available cash was $295,877.  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. At March 31, 2014, the Deficit Amount financed by GEL was $0 and the working capital amount funded by LEH was $3,620,647.  For months in which GEL finances Deficit Amounts, LE does not receive any of its profit share until the Deficit Amounts have been repaid.

We are dedicated to maintaining safe, efficient and reliable refinery operations, improving liquidity and profitability, and focusing on safety and environmental stewardship.   In 2014, we plan to: (i) improve process safety management (“PSM”) standards and develop a PSM program at the Nixon Facility, which is designed to address all aspects of OSHA guidelines for developing and maintaining a comprehensive PSM program, (ii) significantly increase our production of jet fuel, and (iii) continue with refurbishment of key components of the Nixon Facility, including the naphtha stabilizer and depropanizer units, which we anticipate will improve the overall quality of the naphtha that we produce, allow higher recovery of lighter products that can be sold as a liquefied petroleum gas (“LPG”) mix, and increase the amount of throughput that can be processed by the Nixon Facility.

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

For the Current Period, we experienced positive cash flow from operations of $5,199,338.  For the Prior Period, we experienced positive cash flow from operations of $253,705. This represented an increase in cash flow from operations of $4,945,633 for the Current Period compared to the Prior Period, which was primarily due to profitability.

Payments on long-term debt in the Current Period and Prior Period totaled $5,267,116 and $60,876, respectively, which represented an increase in long-term debt payments of $5,206,240 for the comparable periods.

39

Capital expenditures in the Current Period and Prior Period totaled $59,178 and $530,226, respectively, which primarily 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 $579,259 and $5,747,330, including Deficit Amounts, at March 31, 2014 and December 31, 2013, respectively.

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 months ended March 31, 2014 and 2013 as a result of leases expiring and wells being shut-in by operators.  We recognized no abandonment expense in the Current Period compared to $27,451 in the Prior Period.  Abandonment expense in the Prior Period primarily related to plugging and abandonment costs associated with our High Island A-7 oil and gas property.  We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs.

The principal balance outstanding on the Refinery Note was $8,958,892 and $9,057,937 at March 31, 2014 and December 31, 2013, respectively. On June 1, 2013, AFNB and LE agreed to amend the Refinery Note (the “Note Modification Agreement”).  Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310.

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

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

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 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.

In May 2012, we implemented an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products and crude oil inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.

Interest Rate Risk. We are exposed to interest rate volatility with regard to existing variable rate debt tied to movements in the U.S. prime rate. At March 31, 2014, we had $8,958,892 of variable interest debt with a weighted average interest rate of approximately 5.50%.  At March 31, 2014, we performed a sensitivity analysis to determine the impact of an increase in interest rates. Based on this sensitivity analysis, we determined that an increase of 1% in our average floating interest rates at March 31, 2014 would increase interest expense by approximately $89,586 per year.

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.

40

Based on that evaluation, our Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer) concluded that our disclosure controls and procedures were ineffective as of March 31, 2014.   Our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), require us to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the  Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

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

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

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

ITEM 1A.  RISK FACTORS

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

We may be required to post additional collateral in order to satisfy the collateral requirements related to the surety bonds that secure our plugging and abandonment obligations for our pipelines.

We are currently subject to the bonding or security requirements of BOEM for plugging and abandonment obligations for certain of our pipeline segments in federal waters in the U.S. Gulf of Mexico. Failure to post the requisite bonds or otherwise satisfy the BOEM’s security requirements could have an adverse effect on our ability to operate in the U.S. Gulf of Mexico. We engage a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral or post collateral on demand, the amount of which can be increased at the surety companies’ discretion. If these surety companies increase the amount of required collateral, or the BOEM increases the amount of the required surety bond, our available liquidity could be adversely affected. We cannot assure that we will be able to satisfy any additional collateral or bonding requirements.

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

None.

41

ITEM 3.   DEFAULTS UPON SENIOR SECURITIES

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

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

(a)  Exhibits:

The following exhibits are filed herewith:

No.  Description 

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

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

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

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

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Schema Document.

101.CAL XBRL Calculation Linkbase Document.

101.LAB XBRL Label Linkbase Document.

101.PRE XBRL Presentation Linkbase Document.

101.DEF XBRL Definition Linkbase Document.

Remainder of Page Intentionally Left Blank

42

SIGNATURES

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

	BLUE DOLPHIN ENERGY COMPANY (Registrant)
Date: May 15, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary (Principal Executive Officer)

Date: May 15, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

43

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 15, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 15, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2014 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 15, 2014	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2014 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Interim Chief Financial Officer, Treasurer and Assistant Secretary (PrincipalFinancial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date: May 15, 2014	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Interim Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

13. Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Long Term Debt

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

	March 31,		December 31,
	2014		2013
Refinery Note	$	8,958,892	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		579,259		5,747,330
		10,838,151		16,105,267
Less: Current portion of long-term debt		1,000,922		2,215,918
	$	9,837,229	$	13,889,349

XML

11. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Accrued Expenses And Other Current Liabilities Details
Excise and income taxes payable	$ 1,037,001	$ 688,754
Transportation and inspection	138,000	100,000
Property taxes	10,426
Insurance	63,238
Unrealized hedging loss	120,150
Unearned revenue	112,505	302,505
Board of director fees payable	325,000	240,000
Other payable	161,998	269,185
Accrued Expenses and Other Current Liabilities, Net	$ 1,968,318	$ 1,600,444

XML

6. Deposits (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Deposits Details
Utility deposits	$ 17,750	$ 10,250
Equipment deposits		124,526
Tax bonds	792,000	792,000
Purchase option deposits		283,421
Rent deposits	9,463	9,463
Deposits	$ 819,213	$ 1,219,660

XML

12. Asset Retirement Obligations (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Asset Retirement Obligations Details
Asset retirment obligations at December 31, 2013	$ 1,597,661
New asset retirement obligations	300,980
Asset retirement obligation payments/liabilities settled	(127)
Accretion expense	50,802	25,163
Asset retirement obligations as of March 31, 2014	1,949,316
Less: current portion of asset retirement obligations	108,272		107,388
Asset retirement obligations, long-term balance at March 31, 2014	$ 1,841,044		$ 1,490,273

XML

4. Business Segment Information (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenues	$ 120,430,182	$ 109,244,655
Refinery Operations [Member]
Revenues	120,376,151	109,171,507
Operation cost	(113,368,578)	(109,063,677)
Other non-interest income	282,516	278,350
EBITDA	7,290,089	386,180
Capital expenditures	59,178	530,226
Identifiable assets	50,797,212	50,131,322
Segment Pipeline Transportation [Member]
Revenues	54,031	73,148
Operation cost	(122,510)	(154,498)
Other non-interest income	152,697
EBITDA	84,218	(81,350)
Capital expenditures
Identifiable assets	3,201,220	1,662,384
Corporate and Other [Member]
Revenues
Operation cost	(334,729)	(459,145)
Other non-interest income
EBITDA	(334,729)	(459,145)
Capital expenditures
Identifiable assets	530,368	967,906
Total
Revenues	120,430,182	109,244,655
Operation cost	(113,825,817)	(109,677,320)
Other non-interest income	435,213	278,350
Other expense, net	(390,605)	(328,788)
Income (loss) before taxes	(252,277)	(280,228)
Loss from discontinued operations	6,396,696	(763,331)
Capital expenditures	59,178	530,226
Identifiable assets	$ 54,528,800	$ 52,761,612

XML

6. Deposits (Tables)

3 Months Ended

Mar. 31, 2014

Deposits Tables

Deposit balances

Deposit balances consisted of the following:

	March 31,		December 31,
	2014		2013
Utility deposits	$	17,750	$	10,250
Equipment deposits		-		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	819,213	$	1,219,660

XML

13. Long-Term Debt (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery Loan	$ 8,958,892	$ 9,057,937
Notre Dame Debt	1,300,000	1,300,000
Construction and Funding Agreement	579,259	5,747,330
Total	10,838,151	16,105,267
Less: Current portion of long-term debt	1,000,922	2,215,918
Long term debt	$ 9,837,229	$ 13,889,349

XML

20. Fair Value Measurement

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurement

(20) Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at March 31, 2014 and December 31, 2013 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at March 31, 2014 and December 31, 2013 was $10,838,151 and $16,117,151, respectively. The fair value of our debt was determined using a Level 3 hierarchy.

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2014 and the basis for that measurement:

				Fair Value Measurement at March 31, 2014 Using
Financial assets:	Carrying Value at March 31, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(120,150	)	$	(120,150	)	$	-	$	-

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

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

XML

8. Property, Plant and Equipment, Net (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Property Plant And Equipment Net Details
Refinery and facilities	$ 35,852,928	$ 35,852,928
Pipelines and facilities	2,127,207	1,826,226
Onshore separation and handling facilities	325,435	325,435
Land	577,965	577,965
Other property and equipment	567,813	567,813
Property, Plant and Equipment, Gross	39,451,348	39,150,367
Less: Accumulated depletion, depreciation and amortization	3,407,318	3,016,713
Property, Plant and Equipment less depreciation	36,044,030	36,133,654
Construction in Progress	314,189	255,012
Property, Plant and Equipment, Net	$ 36,358,219	$ 36,388,666

XML

20. Fair Value Measurement (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurement

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2014 and the basis for that measurement:

				Fair Value Measurement at March 31, 2014 Using
Financial assets:	Carrying Value at March 31, 2014			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(120,150	)	$	(120,150	)	$	-	$	-

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

XML

11. Accrued Expenses and Other Current Liabilities (Tables)

3 Months Ended

Mar. 31, 2014

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consisted of the following: 

	March 31,		December 31,
	2014		2013
Excise and income taxes payable	$	1,037,001	$	688,754
Transportation and inspection		138,000		100,000
Property taxes		10,426		-
Insurance		63,238		-
Unrealized hedging loss		120,150		-
Unearned revenue		112,505		302,505
Board of director fees payable		325,000		240,000
Other payable		161,998		269,185
	$	1,968,318	$	1,600,444

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10. Note Payable (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Short-Term Note for Financing Costs		$ 9,379
Short-Term Captial Leases		2,505
Note Payable,Total		$ 11,884

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts, USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Commodity Contracts
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ (120,150)		$ 6,950
Cost of refined products sold	$ 127,100	$ 52,050

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17. Leases (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Leases Details Narrative
Rent expense	$ 25,829	$ 29,041

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5. Prepaid Expenses and Other Current Assets (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 138,562	$ 165,004
Prepaid professional fees	104,000	104,000
Prepaid loan closing fees		33,513
Prepaid listing fees	11,250	15,000
Prepaid taxes	9,216	9,216
Unrealized hedging gains		6,950
Prepaid Expenses, Net	$ 263,028	$ 333,683

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4. Business Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Business Segment Information

(4) Business Segment Information

We have two reportable business segments: (i) “Refinery Operations” and (ii) “Pipeline Transportation.”  Business activities related to our “Refinery Operations” business segment are conducted at the Nixon Facility.  Business activities related to our “Pipeline Transportation” business segment are primarily conducted in the U.S. Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.

Segment financials for the three months ended March 31, 2014 (and at March 31, 2014) were as follows:

	Three Months Ended March 31, 2014
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	120,376,151		$	54,031		$	-		$	120,430,182
Operation cost(1)(2)(3)		(113,368,578	)		(122,510	)		(334,729	)		(113,825,817	)
Other non-interest income		282,516			152,697			-			435,213
EBITDA	$	7,290,089		$	84,218		$	(334,729	)
Depletion, depreciation and
amortization											(390,605	)
Other expense, net											(252,277	)
Income before income taxes										$	6,396,696
Capital expenditures	$	59,178		$	-		$	-		$	59,178
Identifiable assets(4)	$	50,797,212		$	3,201,220		$	530,368		$	54,528,800

(1)	“Refinery operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis. Cost of refined products sold within operation cost includes a realized loss of $54,469 and an unrealized loss of $127,100.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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

	Three Months Ended March 31, 2013
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	109,171,507		$	73,148		$	-		$	109,244,655
Operation cost(1)(2)(3)		(109,063,677	)		(154,498	)		(459,145	)		(109,677,320	)
Other non-interest income		278,350			-			-			278,350
EBITDA	$	386,180		$	(81,350	)	$	(459,145	)
Depletion, depreciation and
amortization											(328,788	)
Other expense, net											(280,228	)
Loss before income taxes										$	(763,331	)
Capital expenditures	$	530,226		$	-		$	-		$	530,226
Identifiable assets(4)	$	50,131,322		$	1,662,384		$	967,906		$	52,761,612

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis.  Cost of refined products sold within operation cost includes a realized loss of $36,440 and an unrealized loss of $52,050.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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18. Income Taxes (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Income Taxes Details Narrative
Income tax expense	$ 202,423	$ 0
Accrued Texas margins tax	81,871
Amount of NOLs	18,800,000		11,700,000
Utilized amount of NOLs	1,900,000
Post-merger NOLs	$ 4,100,000

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21. Refined Products Inventory Risk Management (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

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

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

Fair value amounts of derivative instruments

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

		Fair Value
		March 31,	December 31,
Asset Derivatives	Balance Sheets Location	2014	2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$      (120,150)	$            6,950

Effect of derivative instruments

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2014 and 2013: 

		Loss Recognized
		Three Months Ended
		March 31,
Derivatives	Statements of Operations Location	2014		2013
Commodity contracts	Cost of refined products sold	$	127,100	$	52,050

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24. Subsequent Events

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

24. Subsequent Events

(24) Subsequent Events

On May 2, 2014, LRM entered into a Loan and Security Agreement (the “Loan and Security Agreement”) with Sovereign Bank, a Texas state bank, providing for a credit facility to be made to LRM in the aggregate sum of $2.0 million (the “Credit Facility”).  The proceeds of the Credit Facility will be used primarily to finance cost associated with refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility.  The Credit Facility carries a twelve month term and a fixed interest rate of 6.00%.  The Credit Facility contains representations and warranties, affirmative, restrictive, and financial covenants, and events of default which are customary for credit facilities of this type.  The Credit Facility is secured by certain assets of LRM, as well as assets of LEH and its affiliates. In addition, the repayment of funds borrowed and interest accrued under the Credit Facility is personally guaranteed by Jonathan Carroll, Chief Executive Officer and President of Blue Dolphin and majority owner of LEH.

On May 12, 2014, the Management Agreement was amended by: (i) extending the term to August 12, 2015, and (ii) changing the name of the agreement from “Management Agreement” to “Operating Agreement.”  All references to the Management Agreement herein shall mean the “Operating Agreement.”

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23. WBI Transaction

3 Months Ended

Mar. 31, 2014

Wbi Transaction

WBI Transaction

(23) WBI Transaction

On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

We recorded $850,000 of deferred revenue in connection with the WBI transaction. Deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the Pipeline Assets. The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of the pipelines.

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12. Asset Retirement Obligations (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Asset Retirement Obligations Details Narrative
Abandonment expense		$ 27,451

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1. Organization (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Organization Details
Cash and cash equivalents	$ 295,877	$ 434,717	$ 88,059	$ 420,896

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3. Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

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 $295,877 and $434,717 at March 31, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted cash was $1,003,124 and $327,388 at March 31, 2014 and December 31, 2013, respectively. These amounts primarily relate to a payment reserve account required under the Refinery Note.

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 receivable for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $765,996 and $77,388 at March 31, 2014 and December 31, 2013, respectively.

For the three months ended March 31, 2014, we had 4 customers that accounted for approximately 87% of our refined petroleum product sales.  These 4 customers represented approximately $7.4 million in accounts receivable at March 31, 2014.  For the three months ended March 31, 2013, we had 4 customers that accounted for approximately 81% of our refined petroleum product sales.  These 4 customers represented approximately $7.5 million in accounts receivable at March 31, 2013.

Inventory

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

Price-Risk Management Activities

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

Property and Equipment

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included in the Management Agreement and covered by LEH (see “Note (9) Accounts Payable Related Party” and “Note (24) Subsequent Events” of this report for additional disclosures related to the Management Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2014 and 2013.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three months ended March 31, 2014 and 2013 due to leases being relinquished and fields being shut-in by operators.

Pipelines and Facilities Assets. 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 there from.

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

Intangibles - Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

Debt Issue Costs

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

Debt issue costs, net of accumulated amortization, totaled $490,086 and $498,536 at March 31, 2014 and December 31, 2013, respectively.  Accumulated amortization was $185,894 and $177,445 at March 31, 2014 and December 31, 2013, respectively.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2014 and 2013.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

Deferred Revenue.  On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”) and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”), whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed security bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  We recorded $850,000 of deferred revenue in connection with the WBI transaction. Deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the Pipeline Assets.   See “Note (23) WBI Transaction” of this report for additional disclosures related to WBI.

Tank Storage Rental Revenue. Revenue from tank storage rental and land easement agreements are recorded monthly in accordance with the terms of the related lease agreement and included as other income.  The lessee is invoiced monthly for the amount of rent due for the related period.

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

Income Taxes

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

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (18) Income Taxes” of this report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our unaudited consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. 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 our consolidated statements of operations over the service period (generally the vesting period).

Treasury Stock

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

Business Combinations

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

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

Reclassification

We have reclassified certain prior year amounts to conform to our 2014 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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4. Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Business segment reporting

Segment financials for the three months ended March 31, 2014 (and at March 31, 2014) were as follows:

	Three Months Ended March 31, 2014
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	120,376,151		$	54,031		$	-		$	120,430,182
Operation cost(1)(2)(3)		(113,368,578	)		(122,510	)		(334,729	)		(113,825,817	)
Other non-interest income		282,516			152,697			-			435,213
EBITDA	$	7,290,089		$	84,218		$	(334,729	)
Depletion, depreciation and
amortization											(390,605	)
Other expense, net											(252,277	)
Income before income taxes										$	6,396,696
Capital expenditures	$	59,178		$	-		$	-		$	59,178
Identifiable assets(4)	$	50,797,212		$	3,201,220		$	530,368		$	54,528,800

(1)	“Refinery operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis. Cost of refined products sold within operation cost includes a realized loss of $54,469 and an unrealized loss of $127,100.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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

	Three Months Ended March 31, 2013
	Segment
	Refinery			Pipeline			Corporate
	Operations			Transportation			and Other			Total
Revenue	$	109,171,507		$	73,148		$	-		$	109,244,655
Operation cost(1)(2)(3)		(109,063,677	)		(154,498	)		(459,145	)		(109,677,320	)
Other non-interest income		278,350			-			-			278,350
EBITDA	$	386,180		$	(81,350	)	$	(459,145	)
Depletion, depreciation and
amortization											(328,788	)
Other expense, net											(280,228	)
Loss before income taxes										$	(763,331	)
Capital expenditures	$	530,226		$	-		$	-		$	530,226
Identifiable assets(4)	$	50,131,322		$	1,662,384		$	967,906		$	52,761,612

(1)	“Refinery Operations” and “Pipeline Transportation” include an allocation of general and administrative expenses based on respective revenue.
(2)	“Refinery Operations” includes the effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis.  Cost of refined products sold within operation cost includes a realized loss of $36,440 and an unrealized loss of $52,050.
(3)	“Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as director fees and legal expense.
(4)	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.

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3. Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Significant Accounting Policies

 (3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and notes are representations of 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 our consolidated financial statements.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe 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 $295,877 and $434,717 at March 31, 2014 and December 31, 2013, respectively.

Restricted Cash

Restricted cash was $1,003,124 and $327,388 at March 31, 2014 and December 31, 2013, respectively. These amounts primarily relate to a payment reserve account required under the Refinery Note.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $765,996 and $77,388 at March 31, 2014 and December 31, 2013, respectively.

For the three months ended March 31, 2014, we had 4 customers that accounted for approximately 87% of our refined petroleum product sales.  These 4 customers represented approximately $7.4 million in accounts receivable at March 31, 2014.  For the three months ended March 31, 2013, we had 4 customers that accounted for approximately 81% of our refined petroleum product sales.  These 4 customers represented approximately $7.5 million in accounts receivable at March 31, 2013.

Inventory

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

Price-Risk Management Activities

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

Property and Equipment

Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included in the Management Agreement and covered by LEH (see “Note (9) Accounts Payable Related Party” and “Note (24) Subsequent Events” of this report for additional disclosures related to the Management Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2014 and 2013.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our U.S. Gulf of Mexico oil and gas properties were uneconomical for the three months ended March 31, 2014 and 2013 due to leases being relinquished and fields being shut-in by operators.

Pipelines and Facilities Assets. 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 – Other

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2013. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.

Debt Issue Costs

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

Debt issue costs, net of accumulated amortization, totaled $490,086 and $498,536 at March 31, 2014 and December 31, 2013, respectively.  Accumulated amortization was $185,894 and $177,445 at March 31, 2014 and December 31, 2013, respectively.  Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2014 and 2013.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

Revenue Recognition

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

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

Deferred Revenue.  On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”) and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”), whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed security bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  We recorded $850,000 of deferred revenue in connection with the WBI transaction. Deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the Pipeline Assets.   See “Note (23) WBI Transaction” of this report for additional disclosures related to WBI.

Tank Storage Rental Revenue. Revenue from tank storage rental and land easement agreements are recorded monthly in accordance with the terms of the related lease agreement and included as other income.  The lessee is invoiced monthly for the amount of rent due for the related period.

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

Income Taxes

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

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

 In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income prior to the expiration of any net operating loss carryforwards.  See “Note (18) Income Taxes” of this report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our unaudited consolidated statements of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. 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 our consolidated statements of operations over the service period (generally the vesting period).

Treasury Stock

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

Business Combinations

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

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

Reclassification

We have reclassified certain prior year amounts to conform to our 2014 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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5. Prepaid Expenses and Other Current Assets (Tables)

3 Months Ended

Mar. 31, 2014

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid balances consisted of the following:

	March 31,		December 31,
	2014		2013
Prepaid insurance	$	138,562	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		11,250		15,000
Prepaid taxes		9,216		9,216
Unrealized hedging gains		-		6,950
	$	263,028	$	333,683

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16. Concentration of Risk (Tables)

3 Months Ended

Mar. 31, 2014

Concentration Of Risk Tables

Percentages of all refined petroleum products sales to total sales

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

	Three Months Ended March 31,
	2014			2013
Low-sulfur diesel		32.2	%		49.7	%
Naphtha		23.9	%		26.0	%
Atmospheric gas oil		27.1	%		24.1	%
LPG mix		0.1	%		0.0	%
Reduced crude		0.0	%		0.2	%
Jet fuel		16.7	%		0.0	%
		100.0	%		100.0	%

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10. Note Payable (Details Narrative) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Note Payable Details Narrative
Short-Term Note for Financing Costs		$ 9,379
Short-Term Captial Leases		$ 2,505

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$ 295,877	$ 434,717
Restricted cash	1,003,124	327,388
Accounts receivable	9,749,014	13,487,106
Prepaid expenses and other current assets	263,028	333,683
Deposits	819,213	1,219,660
Inventory	4,396,893	4,686,399
Total current assets	16,527,149	20,488,953
Total property and equipment, net	36,358,219	36,388,666
Surety bonds	850,000
Debt issue costs, net	490,086	498,536
Trade name	303,346	303,346
TOTAL ASSETS	54,528,800	57,679,501
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	15,863,920	20,783,541
Accounts payable, related party	3,620,647	3,659,340
Note payable		11,884
Asset retirement obligations, current portion	108,272	107,388
Accrued expenses and other current liabilities	1,968,318	1,600,444
Interest payable, current portion	41,205	40,272
Long-term debt, current portion	1,000,922	2,215,918
Total current liabilities	22,603,284	28,418,787
Asset retirement obligations, net of current portion	1,841,044	1,490,273
Deferred revenues and expenses	821,187
Long term debt, net of current portion	9,837,229	13,889,349
Long term interest payable, net of current portion	1,118,072	1,767,381
Total long-term liabilities	13,617,532	17,147,003
TOTAL LIABILITIES	36,220,816	45,565,790
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,580,973 shares issued at March 31, 2014 and December 31, 2013)	105,810	105,810
Additional paid-in capital	36,623,965	36,623,965
Accumulated deficit	(17,621,791)	(23,816,064)
Treasury stock, 150,000 shares and 0 shares, respectively, at cost	(800,000)	(800,000)
Total stockholders' equity	18,307,984	12,113,711
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 54,528,800	$ 57,679,501

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3. Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Cash and cash equivalents	$ 295,877	$ 88,059	$ 434,717	$ 420,896
Restricted cash	1,003,124		327,388
Perecentage of revenue from major customers	87.00%	81.00%
Four major customers accounts recievable	7,400,000		7,500,000
Accumulated amortization	185,894		177,445
Uninsured balances	765,996		77,388
Amortization expense	8,450
Debt issuance costs	$ 490,086		$ 498,536

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1. Organization

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

(1) Organization

Nature of Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company.  We are primarily an independent refiner and marketer of petroleum products.  Our primary operating asset is a 56-acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  Operations at the Nixon Facility also involve the storage and terminaling of petroleum under third-party lease agreements. We also own and operate pipeline assets and have leasehold interests in oil and gas properties, which are considered non-core to our business. See “Note (4) Business Segment Information” of this report for further discussion of our business segments.

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

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

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

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

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

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

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

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

Operating Risks

We had cash and cash equivalents of $295,877 and $434,717 at March 31, 2014 and December 31, 2013, respectively. As of March 31, 2014, we were in violation of certain financial covenants in a loan agreement dated September 29, 2008 (the “Loan Agreement”) by and between LE and First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000 (the “Refinery Note”).  In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”).  We are currently making our scheduled payments in accordance with the terms and conditions of the Loan Agreement and, as of December 31, 2013, we obtained a waiver for these financial covenants effective through December 31, 2014.  See “Note (13) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

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

We believe that our operational strategy, including our introduction and production of jet fuel beginning in the third quarter of 2013 and the continued refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility, will be sufficient to support our operations over the next twelve months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

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15. Treasury Stock (Details Narrative)	Mar. 31, 2014	Dec. 31, 2013
Treasury Stock Details Narrative
Treasury stock	150,000	0

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

3 Months Ended

Mar. 31, 2014

Property, Plant and Equipment [Abstract]

Property and equipment

Property and equipment consisted of the following:

	March 31,		December 31,
	2014		2013
Refinery and facilities	$	35,852,928	$	35,852,928
Pipelines and facilities		2,127,207		1,826,226
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		567,813		567,813
		39,451,348		39,150,367
Less:  Accumulated depletion, depreciation and amortization		3,407,318		3,016,713
		36,044,030		36,133,654
Construction in Progress		314,189		255,012
Property, Plant and Equipment, Net	$	36,358,219	$	36,388,666

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20. Fair Value Measurement (Details Narrative) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Fair Value Measurement Details Narrative
Fair value of longer term debt	$ 10,838,151	$ 16,117,152

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17. Leases

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Leases

(17) 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 payment is $9,685 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 March 31, 2014 and 2013, rent expense for the office lease was $25,829 and $29,041, respectively.

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10. Note Payable (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Notes payable

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

	March 31,		December 31,
	2014		2013
Short-Term Note for Financing Costs	$	-	$	9,379
Short-Term Captial Leases		-		2,505
	$	-	$	11,884

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19. Earnings Per Share

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share

(19) Earnings Per Share

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

	Three Months Ended
	March 31,
	2014		2013
Net income (loss)	$	6,194,273	$	(763,331	)
Basic and diluted income (loss) per share	$	0.59	$	(0.07	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,430,973		10,510,334

Diluted EPS is computed by dividing net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2014 excluded stock options as there were no stock options outstanding under the Plan.  Diluted EPS for the three months ended March 31, 2013 excludes stock options as they would be anti-dilutive

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22. Commitments and Contingencies (Details Narrative) (USD $)	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Advances and Deficit Amounts	$ 579,259
Deficit Amount under the Construction and Funding Agreement	$ 0

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2. Basis of Presentation

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Basis of Presentation

(2) Basis of Presentation

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

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,580,973	10,580,973
Treasury stock, shares	150,000	0

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12. Asset Retirement Obligations

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(12) Asset Retirement Obligations

Refinery and Facilities

Management has concluded that there is no legal or contractual obligation to dismantle or remove the Nixon Refinery and related facilities 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.

Pipelines and Facilities Assets and Oil and Gas Properties

We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Effective December 31, 2013, we updated our estimates in computing the estimated ARO for the abandonment in place of our pipelines and an associated platform.

The following provides a roll-forward of our AROs:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(127	)
Accretion expense		50,802
		1,949,316
Less:  current portion of asset retirement obligations		108,272
Asset retirement obligations, long-term balance
at March 31, 2014	$	1,841,044

On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. Once plugging and abandonment work has been completed, the collateral will be released to BDPL.  The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of the pipelines.   See “Note (23) WBI Transaction” of this report for additional disclosures related to WBI.

For the three months ended March 31, 2014, we recognized $0 in abandonment expense related to our oil and gas properties.  For the three months ended March 31, 2013, we recognized $27,451 in abandonment expense for AROs associated with our HI-A7 oil and gas property. We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	May 15, 2014
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,446,218
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2014

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13. Long-Term Debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Long-Term Debt

(13) Long-Term Debt

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

	March 31,		December 31,
	2014		2013
Refinery Note	$	8,958,892	$	9,057,937
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		579,259		5,747,330
		10,838,151		16,105,267
Less: Current portion of long-term debt		1,000,922		2,215,918
	$	9,837,229	$	13,889,349

Refinery Note.   The Refinery Note accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at March 31, 2014) and has a maturity date of October 1, 2028 (the “Maturity Date”).  LE’s obligations under the Refinery Note are secured by a Deed of Trust (the “Deed of Trust”) of even date with the Loan Agreement.  The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Loan Agreement, the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE.  The principal balance outstanding on the Refinery Note was $8,958,892 and $9,057,937 at March 31, 2014 and December 31, 2013, respectively.  Interest was accrued on the Refinery Note in the amount of $41,205 and $40,132 at March 31, 2014 and December 31, 2013, respectively.  See “Note (1) Organization – Operating Risks” of this report for additional disclosures related to the Refinery Note.

 The Loan Agreement has two financial covenants relating to a current ratio and debt-to-worth.  As of March 31, 2014, we were in violation of the current ratio covenant. However, as of December 31, 2013, we obtained a waiver related to the financial covenants effective through December 31, 2014.   We expect to be in compliance with the financial covenants upon termination of the waiver period.  Accordingly, the Refinery Note has been classified as long-term on our consolidated balance sheets.

In October 2011, the Refinery Loan Documents were acquired by AFNB.  On 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.  Payments under the Construction and Funding Agreement began 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 $579,259 and $5,747,330 at March 31, 2014 and December 31, 2013, respectively. Interest was accrued on the Construction and Funding Agreement in the amount of $0 and $700,597 at March 31, 2014 and December 31, 2013, respectively.  There are no financial covenants associated with this obligation.

See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to amendments and/or modifications to the Crude Supply Agreement, Construction and Funding Agreement and Joint Marketing Agreement.

Notre Dame Debt.  LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8,000,000, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt accrues interest at a rate of 16% and is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  The principal balance outstanding on the Notre Dame Debt was $1,300,000 at March 31, 2014 and December 31, 2013.  Interest was accrued on the Notre Dame Debt in the amount of $1,118,072 and $1,066,784 at March 31, 2014 and December 31, 2013, respectively.  There are no financial covenants associated with the Notre Dame Debt.  The due date of the Notre Dame Debt was extended to July 1, 2015.

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

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

Pursuant to a First Amendment to Promissory Note made effective July 1, 2013, the Notre Dame Debt was amended as follows:  (i) the annual interest rate on the unpaid balance was set to 16% and (ii) the final maturity became July 1, 2015.

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
REVENUE FROM OPERATIONS
Refined product sales	$ 120,376,151	$ 109,171,507
Pipeline operations	54,031	73,148
Total revenue from operations	120,430,182	109,244,655
COST OF OPERATIONS
Cost of refined products sold	110,415,607	106,322,661
Refinery operating expenses	2,955,019	2,745,209
Pipeline operating expenses	27,729	45,371
Lease operating expenses	7,176	26,901
General and administrative expenses	369,484	484,564
Depletion, depreciation and amortization	390,605	328,788
Abandonment expense		27,451
Accretion expense	50,802	25,163
Total cost of operations	114,216,422	110,006,108
Income (loss) from operations	6,213,760	(761,453)
OTHER INCOME (EXPENSE)
Net tank rental and easement revenue	407,516	278,350
Interest and other income	29,220	835
Interest expense	(253,800)	(281,063)
Total other income (expense)	182,936	(1,878)
Income (loss) before income taxes	6,396,696	(763,331)
Income tax expense, current	(202,423)
Net income (loss)	$ 6,194,273	$ (763,331)
Income (loss) per common share
Basic	$ 0.59	$ (0.07)
Diluted	$ 0.59	$ (0.07)
Weighted average number of common shares outstanding:
Basic	10,430,973	10,510,334
Diluted	10,430,973	10,510,334

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7. Inventory

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventories

(7) Inventory

Inventory balances consisted of the following:

	March 31,		December 31,
	2014		2013
Low-sulfur diesel	$	231,756	$	1,813,662
Naphtha		670,156		804,490
Atmospheric gas oil		527,430		575,919
Jet fuel		2,852,755		1,444,399
LPG mix		95,755		28,888
Crude		19,041		19,041
	$	4,396,893	$	4,686,399

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6. Deposits

3 Months Ended

Mar. 31, 2014

Banking and Thrift [Abstract]

Deposits

(6) Deposits

Deposit balances consisted of the following:

	March 31,		December 31,
	2014		2013
Utility deposits	$	17,750	$	10,250
Equipment deposits		-		124,526
Tax bonds		792,000		792,000
Purchase option deposits		-		283,421
Rent deposits		9,463		9,463
	$	819,213	$	1,219,660

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18. Income Taxes

3 Months Ended

Mar. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

(18) Income Taxes

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

Section 382 of the Internal Revenue Code imposes a limitation on the use of Blue Dolphin’s NOLs generated prior to the reverse merger.  The amount of NOLs subject to such limitation is approximately $18.8 million, of which approximately $1.9 million is projected to be utilized during the three months ended March 31, 2014.  NOLs generated subsequent to the reverse merger through December 31, 2013 of approximately $11.7 million are not subject to any such limitation. Approximately $4.1 million of the post-merger NOLs are projected to be utilized during the three months ended March 31, 2014.  For the three months ended March 31, 2014, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

For the three months ended March 31, 2014 and 2013, income tax expense was $202,423 and $0, respectively. Income tax expense related to state and federal income tax.  The federal income tax generated of $120,552 was the result of a valuation allowance on the alternative minimum tax deferred tax asset.  The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state of Texas’ prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax.  At March 31, 2014, we accrued $81,871 in TMT.

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14. Stock Options

3 Months Ended

Mar. 31, 2014

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

Stock Options

(14) Stock Options

Blue Dolphin’s Board established a 2000 Stock Incentive Plan (the “Plan”) on April 14, 2000 and the Plan was subsequently approved by Blue Dolphin’s stockholders on May 18, 2000.  The Plan offered incentive awards to employees, including officers (whether or not they are directors), consultants and non-employee directors. The Plan has undergone several amendments, as follows:  (i) Amendment No. 1 -- 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, (ii) Amendment No. 2 -- 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, (iii) Amendment No. 3 -- 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, (iv) Amendment No. 4 -- 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.

Although the Compensation Committee of the Board of Directors (the “Board”) approved continuation of the Plan following Blue Dolphin’s reverse merger with LE in 2012, pursuant to the Management Agreement, all employees of Blue Dolphin became employees of LEH effective February 15, 2012.  As a result, with the exception of options outstanding for Ivar Siem, options outstanding for Blue Dolphin employees were cancelled 90 days following the effective date of the Management Agreement.  All of Mr. Siem’s options expired in October 2013.

For the three months ended March 31, 2014 and 2013 there were no stock options granted under the Plan.  For the three months ended March 31, 2014 and 2013, we recognized no compensation expense for vested stock options.

At March 31, 2014, there were no options outstanding, no options exercisable or no shares of common stock reserved for issuance under the Plan.  As of March 31, 2014, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

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10. Note Payable

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Note Payable

 (10) Notes Payable

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

	March 31,		December 31,
	2014		2013
Short-Term Note for Financing Costs	$	-	$	9,379
Short-Term Captial Leases		-		2,505
	$	-	$	11,884

Short-Term Note for Financing Services.  The balance on a short-term note issued in January 2010 in the amount of $100,000 as payment for financing services was $0 and $9,379 at March 31, 2014 and December 31, 2013, respectively.  The unsecured note, which bore interest at a base rate of 10% and a default rate of 18%, was paid off during the first quarter of 2014. 

Short-Term Capital Leases.  The balance on short-term notes under capital lease agreements was $0 and $2,505 at March 31, 2014 and December 31, 2013, respectively.  These capital leases, which had interest rates ranging from 0% to 13.04%, were paid off during the first quarter of 2014.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

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16. Concentration of Risk (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Concentration Risk	100.00%	100.00%
Low-sulfur diesel
Concentration Risk	32.20%	49.70%
Naphtha
Concentration Risk	23.90%	26.00%
Atmospheric gas oil
Concentration Risk	27.10%	24.10%
LPG mix [Member]
Concentration Risk	0.10%	0.00%
Reduced crude [Member]
Concentration Risk	0.00%	0.20%
Jet Fuel [Member]
Concentration Risk	16.70%	0.00%

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8. Property, Plant and Equipment, Net

3 Months Ended

Mar. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

(8) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	March 31,		December 31,
	2014		2013
Refinery and facilities	$	35,852,928	$	35,852,928
Pipelines and facilities		2,127,207		1,826,226
Onshore separation and handling facilities		325,435		325,435
Land		577,965		577,965
Other property and equipment		567,813		567,813
		39,451,348		39,150,367
Less:  Accumulated depletion, depreciation and amortization		3,407,318		3,016,713
		36,044,030		36,133,654
Construction in Progress		314,189		255,012
Property, Plant and Equipment, Net	$	36,358,219	$	36,388,666

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9. Accounts Payable, Related Party

3 Months Ended

Mar. 31, 2014

Payables and Accruals [Abstract]

Accounts Payable, Related Party

(9) Accounts Payable, Related Party

LEH, which owns approximately 81% of our outstanding common stock, par value $0.01 per share (the “Common Stock”), manages all of our subsidiaries and operates all of our assets, including the Nixon Facility, (the “Services”) pursuant to a Management Agreement dated February 15, 2012 (the “Management Agreement”).  Jonathan Carroll, Chief Executive Officer and President of Blue Dolphin, is the majority owner of LEH.

With respect to the Nixon Facility, the Management Agreement represents, in effect, an operating agreement that covers all refinery operating expenses with the exception of capital expenditures.  Pursuant to the Management Agreement, for management and operation of the Nixon Facility, LEH receives as compensation: (i) weekly payments from GEL not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the 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. For all other assets, LEH is reimbursed at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month.

The Management Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement, which has an initial term of three years and successive one-year renewals until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice, (b) August 12, 2015, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party.

Aggregate amounts expensed for Services at the Nixon Facility for the three months ended March 31, 2014 and 2013 were $2,955,019 (approximately $2.71 per barrel of throughput) and $2,745,209 (approximately $2.80 per barrel of throughput). At March 31, 2014 and December 31, 2013, the amounts outstanding to LEH to fund our working capital requirements were $3,620,647 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.

See “Note (24) Subsequent Events” on this report for further disclosures related to the Management Agreement.

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11. Accrued Expenses and Other Current Liabilities

3 Months Ended

Mar. 31, 2014

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

 (11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following: 

	March 31,		December 31,
	2014		2013
Excise and income taxes payable	$	1,037,001	$	688,754
Transportation and inspection		138,000		100,000
Property taxes		10,426		-
Insurance		63,238		-
Unrealized hedging loss		120,150		-
Unearned revenue		112,505		302,505
Board of director fees payable		325,000		240,000
Other payable		161,998		269,185
	$	1,968,318	$	1,600,444

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20. Fair Value Measurement (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Financial liabilties:
Commodity contracts	$ (120,150)	$ 6,950
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	(120,150)	6,950
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Mar. 31, 2014
Refined products - net short (long) positions
Volume in Thousands of barrels
Notional Contract Volumes 2014	45,000
Notional Contract Volumes 2015	0
Notional Contract Volumes 2016	0

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19. Earnings per share (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share [Abstract]
Net income (loss)	$ 6,194,273	$ (763,331)
Basic and diluted earnings (loss) per common share
Basic and diluted income (loss) per share	$ 0.59	$ (0.07)
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,430,973	10,510,334

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7. Inventories (Tables)

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventory

Inventory balances consisted of the following:

	March 31,		December 31,
	2014		2013
Low-sulfur diesel	$	231,756	$	1,813,662
Naphtha		670,156		804,490
Atmospheric gas oil		527,430		575,919
Jet fuel		2,852,755		1,444,399
LPG mix		95,755		28,888
Crude		19,041		19,041
	$	4,396,893	$	4,686,399

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9. Accounts Payable, Related Party Transactions (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Payables and Accruals [Abstract]
Expense for service	$ 2,955,019	$ 2,745,209
Accounts payable, related party	$ 3,620,647		$ 3,659,340

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16. Concentration of Risk

3 Months Ended

Mar. 31, 2014

Risks and Uncertainties [Abstract]

Concentration of Risk

(16) Concentration of Risk

Significant Customers.  Customers of our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area).  We have bulk term contracts, including month-to-month, six month and up to five year terms, in place with most of our customers.  Certain of our contracts require us to sell fixed quantities and/or minimum quantities and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products.  See “Note (2) Basis of Presentation” of this report for additional disclosures related to significant customers.

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

	Three Months Ended March 31,
	2014			2013
Low-sulfur diesel		32.2	%		49.7	%
Naphtha		23.9	%		26.0	%
Atmospheric gas oil		27.1	%		24.1	%
LPG mix		0.1	%		0.0	%
Reduced crude		0.0	%		0.2	%
Jet fuel		16.7	%		0.0	%
		100.0	%		100.0	%

In mid-September of 2013, the Nixon Facility began producing jet fuel – the Nixon Facility’s fifth saleable refined petroleum product.  Jet fuel is produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream.  Production of jet fuel, which is considered a higher value product, significantly upgrades the value of the naphtha component.

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement.  On October 30, 2013, LE entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam (the “October 2013 Letter Agreement”), effective October 24, 2013.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

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21. Refined Petroleum Products and Crude Oil Inventory Risk Management

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products and Crude Oil Inventory Risk Management

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

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

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

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

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

As of March 31, 2014, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels):

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

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

		Fair Value
		March 31,	December 31,
Asset Derivatives	Balance Sheets Location	2014	2013
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$      (120,150)	$            6,950

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2014 and 2013: 

		Loss Recognized
		Three Months Ended
		March 31,
Derivatives	Statements of Operations Location	2014		2013
Commodity contracts	Cost of refined products sold	$	127,100	$	52,050

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7. Inventory (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 231,756	$ 1,813,662
Naphtha	670,156	804,490
Atmospheric gas oil	527,430	575,919
Jet fuel	2,852,755	1,444,399
LPG mix	95,755	28,888
Crude	19,041	19,041
Inventories, Net	$ 4,396,893	$ 4,686,399

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19. Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings per share

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

	Three Months Ended
	March 31,
	2014		2013
Net income (loss)	$	6,194,273	$	(763,331	)
Basic and diluted income (loss) per share	$	0.59	$	(0.07	)
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,430,973		10,510,334

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
OPERATING ACTIVITIES
Net income (loss)	$ 6,194,273	$ (763,331)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	390,605	328,788
Unrealized loss on derivatives	127,100	52,050
Amortization of debt issue costs	8,450	8,450
Amortization of intangible assets		9,463
Accretion expense	50,802	25,163
Abandonment costs incurred		27,451
Common stock issued for services		50,000
Changes in operating assets and liabilities
Restricted cash	(675,736)	62,245
Accounts receivable	3,738,092	4,087,965
Prepaid expenses and other current assets	70,655	19,355
Deposits and other assets	(449,553)	(9,463)
Inventory	289,506	(1,489,100)
Accounts payable, accrued expenses and other liabilities	(4,506,163)	(2,739,371)
Accounts payable, related party	(38,693)	584,040
Net cash provided by operating activities	5,199,338	253,705
INVESTING ACTIVITIES
Capital expenditures	(59,178)	(530,226)
Net cash used in investing activities	(59,178)	(530,226)
FINANCING ACTIVITIES
Payments on long term debt	(5,267,116)	(60,876)
Proceeds from notes payable		15,032
Payments on notes payable	(11,884)	(10,472)
Net cash used in financing activities	(5,279,000)	(56,316)
Net decrease in cash and cash equivalents	(138,840)	(332,837)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	434,717	420,896
CASH AND CASH EQUIVALENTS AT END OF PERIOD	295,877	88,059
Non-cash operating activities
Reduction in accounts receivable in exchange for treasury stock received		800,000
Surety bond funded by seller of pipeline interest holder	850,000
Non-cash investing and financing activities:
New asset retirement obligations	300,980
Accrued services payable converted to common stock		50,000
Interest paid	$ 902,176	$ 232,577

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5. Prepaid Expenses and Other Current Assets

3 Months Ended

Mar. 31, 2014

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

Prepaid Expenses and Other Current Assets

(5) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	March 31,		December 31,
	2014		2013
Prepaid insurance	$	138,562	$	165,004
Prepaid professional fees		104,000		104,000
Prepaid loan closing fees		-		33,513
Prepaid listing fees		11,250		15,000
Prepaid taxes		9,216		9,216
Unrealized hedging gains		-		6,950
	$	263,028	$	333,683

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13. Long-Term Debt (Details Narrative) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Refinery Note	$ 8,958,892	$ 9,057,937
Refinery loan accrued interest	41,205	40,132
Notre Dame debt accrued interest	1,118,072	1,066,784
Construction and Funding Agreement	579,259	5,747,330
Construction funding accrued interest	0	700,597
Effective rate	16.00%
Notre Dame Debt	$ 1,300,000	$ 1,300,000

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22. Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(22) Commitments and Contingencies

Management Agreement

See “Note (9) Accounts Payable, Related Party” and “Note (24) Subsequent Events” 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. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

● Construction and Funding Agreement.  Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam 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:  (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.

In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility.  All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement will constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.

● Joint Marketing Agreement.  The Joint Marketing Agreement sets forth the terms of 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 Investment Threshold Date, if GEL sustains losses, it can recoup those losses by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated.

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances.  For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above.  The Joint Marketing Agreement had an initial term of three years expiring on August 12, 2014.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

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

(a) In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our 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 March 31, 2014, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $579,259.  As of March 31, 2014, 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 $0.

Sales Commitments

We have a sales commitment with a significant customer to sell Non-Road, Locomotive and Marine Diesel fuel (“NRLM”) at a market based price less a fixed margin.  The agreement allows the customer to purchase 80% of the NRLM that we produce and requires us to sell a minimum of 2,380,000 barrels through December 31, 2017. We have sold more than 2,000,000 barrels to date under this agreement.  Subsequent to the balance sheet date, we amended the agreement with the customer to begin selling oil based mud blend stock effective June 1, 2014, instead of NRLM, at a market based price less a fixed margin.  Under the amended agreement, the customer must purchase 80% of the oil based mud blend stock that we produce or 100% if our monthly production is less than 2,625 barrels per day. We plan to produce the oil based mud blend stock as of June 1, 2014 to meet this contractual requirement.

Master Easement Agreement - BDPL and FLNG Land

On December 11, 2013 (the “Effective Date”), BDPL and FLNG Land, II, Inc., a Delaware corporation (“FLNG”), entered into a Master Easement Agreement (the “Master Easement Agreement”) whereby BDPL is providing FLNG with: (i) free and uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG (the “Access Easement”) and (ii) a perpetual permanent pipeline easement and right of way across certain property of BDPL to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”).  As initial consideration for the grant of the Easements, FLNG paid BDPL the sum of $250,000 (the “Initial Payment”) on the Effective Date.  FLNG has the option to terminate the Master Easement Agreement within ten (10) months of the Effective Date.  If FLNG commences improvements within the Access Easement or commences construction within the Pipeline Easement (the “Commencement Date”), FLNG shall make a second payment of $250,000 to BDPL (the “Second Payment”).

If FLNG elects to make the Second Payment, then on or before the first anniversary of the Commencement Date through the greater of: (i) the fifth anniversary of said date or (ii) the date on which the third of FLNG’s planned liquefaction pre-treatment train facilities has reached completion sufficient to permit its start-up and initial operational testing, FLNG shall make annual payments of $500,000 (“the Annual Payments”) to BDPL. Upon delivery of the Initial Payment, Second Payment, and each of the remaining Annual Payments, the Easements shall be fully paid for by FLNG.  One year after the final Annual Payment is made, FLNG will begin paying to BDPL  annual payments of $10,000 for so long as FLNG desires to use the Access Easement.  The terms of the Easements are perpetual, unless terminated by FLNG prior to the Commencement Date or if FLNG elects to permanently cease use of the Access Easement or Pipeline Easement, as applicable.

Supplemental Pipeline Bonds

On February 5, 2014, WBI and BDPL entered into Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a cash-backed surety bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  The bond increased the collateral held by a surety company relating to supplemental pipeline bonds issued on behalf of BDPL to satisfy the bonding requirements of the Bureau of Ocean Energy Management.  These supplemental pipeline bonds are intended to secure the performance of BDPL’s plugging and abandonment obligations with respect to pipeline segments in federal waters of the U.S. Gulf of Mexico.  Once plugging and abandonment work has been completed, the collateral will be released to BDPL.

LTRI Option

In June 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Texas Refinery I, LLC (“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.  The LTRI Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LTRI.

LED Option

In connection with the reverse merger with LE in 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Energy Development, LLC (“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.   The LED Option expired on December 31, 2013, and the deposit we paid was applied to the outstanding balance of accounts payable, related party.  The parties have endeavored to negotiate a transaction that is fair and in the best interest of our stockholders.  However, there can be no assurance that the parties will reach agreeable terms or finalize a transaction for the acquisition of LED.

Legal Matters

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

Health, Safety and Environmental Matters

All of our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of 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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12. Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

The following provides a roll-forward of our AROs:

Asset retirment obligations at December 31, 2013	$	1,597,661
New asset retirement obligations		300,980
Asset retirement obligation payments/liabilities settled		(127	)
Accretion expense		50,802
		1,949,316
Less:  current portion of asset retirement obligations		108,272
Asset retirement obligations, long-term balance
at March 31, 2014	$	1,841,044

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15. Treasury Stock

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Treasury Stock

(15) Treasury Stock

During the three months ended March 31, 2013, BDEX completed a non-cash transaction to dispose of its 7% undivided working interest in an oil property located in Indonesia (“Indonesia”) pursuant to a Sale and Purchase Agreement with Blue Sky Langsa, Ltd. (“Blue Sky”) dated November 6, 2012.   Blue Sky’s consideration to BDEX for Indonesia was 150,000 shares of Common Stock, which represented a recovery of a significant portion of the 342,857 shares of Common Stock BDEX paid Blue Sky to acquire Indonesia in 2010. We are holding the 150,000 shares acquired from Blue Sky as treasury stock.  As of March 31, 2014 and December 31, 2013, we had 150,000 shares of treasury stock.