10-K

­UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

or

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

For the transition period from to .

Commission File No. 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)	(Zip Code)

 (713) 568-4725

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.01 per share	OTCQX

Securities registered pursuant to Section 12(g) of the Act:

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has 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 ¨

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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Act.

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller Reporting Company þ

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

Aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2012 was approximately $14,361,145 million based on the closing price of $7.95 per share on the OTCQX.

Number of shares of Common Stock outstanding as of March 29, 2012 10,563,297

BLUE DOLPHIN ENERGY COMPANY

FORM 10-K REPORT INDEX

PART I
ITEM 1.	BUSINESS	5
ITEM 1A.	RISK FACTORS	21
ITEM 1B.	UNRESOLVED STAFF COMMENTS	29
ITEM 2.	PROPERTIES	29
ITEM 3.	LEGAL PROCEEDINGS	30
ITEM 4.	MINE SAFETY DISCLOSURES	30
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
ITEM 6.	SELECTED FINANCIAL DATA	32
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	43
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	44
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	83
ITEM 9A.	CONTROLS AND PROCEDURES	83
ITEM 9B.	OTHER INFORMATION	84
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	85
ITEM 11.	EXECUTIVE COMPENSATION	89
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	91
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	92
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	93
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	94
SIGNATURES		100

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FORWARD LOOKING STATEMENTS

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Annual Report on Form 10-K, and in particular under the sections entitled “Part I, Item 1. Business,” “Part I, Item 3. Legal Proceedings” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.

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

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

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

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

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

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

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

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

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

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

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

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

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

● operating hazards such as fires and explosions;

● insurance coverage limitations;

● environmental costs and liabilities associated with our operations;

● retention and recruitment of key employees;

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

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

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

● competition from larger companies;

● acquisition expenses and integration difficulties; and

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

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

Remainder of Page Intentionally Left Blank

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PART I

ITEM 1.  BUSINESS

The Company

Blue Dolphin Energy Company (www.blue-dolphin-energy.com), a Delaware corporation (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) was formed in 1986 as a holding company. We conduct substantially all of our operations through our wholly-owned subsidiaries. We acquired LE, the primary asset of which is the Nixon Facility, from LEH in February 2012 (the “LE Acquisition”). The transaction resulted in a change in control of Blue Dolphin with LEH owning approximately eighty percent (80%) of our issued and outstanding common stock, par value $0.01 per share (the "Common Stock"). The combined company operates under the name Blue Dolphin Energy Company. The LE Acquisition was accounted for as a “reverse acquisition.” Under reverse acquisition accounting LE (the legal subsidiary) was treated as the accounting parent (acquirer) and Blue Dolphin (the legal parent) was treated as the accounting subsidiary (acquiree). Accordingly, the financial statements subsequent to the date of the transaction are presented as the continuation of LE.

As a result of our acquisition of LE and Lazarus Refining & Marketing, LLC (“LRM”) in October 2012, we are primarily an independent refiner and marketer of petroleum products. As part of our refining business segment we also conduct petroleum storage and terminaling operations through LRM. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refining Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel, asphalt and other products. The typical refining process for most refineries involves numerous stages to create final products. However, the Nixon Facility currently engages in the first stage of the refining process. Refining is primarily a margin-based business where the crude oil and other feedstocks and refined products are commodities with fluctuating prices. In order to increase profitability, it is important for a refinery to maximize the yields of finished products and to minimize the costs of crude oil and other feedstocks and operating expenses, and to do so without compromising safety and environmental performance. According to the U.S. Energy Information Administration (the “EIA”), as of January 1, 2012, there were 134 oil refineries operating in the United States. High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. Domestic operating refining capacity increased approximately 4% between January 1982 and January 2012, from 16.1 million barrels per day (“bpd”) to 16.7 million bpd, according to the EIA. Much of this increase in capacity is the result of efficiency measures and moderate expansions at various refineries, known as “capacity creep,” but some significant expansions at existing refineries have occurred as well. During this same time period, more than 120 smaller and less efficient refineries that had limited access to a wide variety of crude oils or were unable to profitably process feedstock into a marketable product mix were closed.

Crude oil supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a given refinery’s location. Our Nixon Facility is located in the Gulf Coast region of the United States, which is represented in part as PADD III by the EIA.

According to the EIA, total demand for refined products in PADD III represented approximately 20.9% of total U.S. refined products demand from 2007 to 2011. Total refinery capacity for PADD III in May 2012 was 8.7 million bpd with total throughput at 8.2 million bpd, representing a refinery utilization rate of approximately 93.8%. Refinery capacity exceeds refined product demand with finished petroleum products consumed in the region totaling 3.5 million bpd, causing refiners in PADD III to supply all other PADDs. Despite this high level of refining capacity relative to the refined product demand, refiners who can access advantageous crude supplies are still able to achieve high margins.

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The following map illustrates U.S. oil refinery capacity as of July 2012:

Source: EIA, Refinery Capacity Report, 2012.

Business Strategies

Our management team is dedicated to improving our operations by executing the following strategies:

●   Concentrate on Stable Cash Flows - We intend to continue to focus on operating assets and businesses that generate stable cash flows;

●   Maintain Efficient Refinery Operations and Promote Operational Excellence and Reliability - For the year ended December 31, 2012, our Nixon Facility maintained a utilization rate of approximately 65%. We intend to continue to operate our refinery as reliably and efficiently as possible to optimize utilization and further improve our operations by maintaining our costs at competitive levels. We will continue to devote significant time and resources toward improving the reliability of our operations. We will also seek to improve operating performance through commitment to our preventive maintenance program and to employee training and development programs;

●   Enhance Profitability of Our Existing Assets and Invest in Organic Growth - We are focused on the profitable enhancement of our existing operations by:

-   continuing to make investments to enhance the operating flexibility of the Nixon Facility;

-   pursuing organic growth projects at the Nixon Facility to increase utilization and  improve the efficiency of our operations; and

-   optimizing current operations through energy savings initiatives, product quality enhancements and product yield improvements.

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●   Pursue Strategic and Complementary Acquisitions - We will seek to acquire assets and product lines where we can enhance operations and improve profitability in geographic or product areas that would diversify our operating footprint. In addition, we may also pursue accretive acquisitions within our refining operations, both in our existing areas of operations as well as in new geographic regions that would also diversify our operating footprint. In evaluating acquisitions within the refining industry, we will consider, among other factors, sustainable financial performance of the targeted assets through the refining cycle, access to advantageous sources of crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure, and potential operating synergies.

Recent Developments

In February 2013, we announced that our Board of Directors (the “Board”) has decided to explore strategic alternatives intended to enhance stockholder value, specifically our conversion from a corporation into a master limited partnership. A special committee of independent directors was established to explore the feasibility of our conversion from a corporation into a master limited partnership and has engaged Stout Risius Ross to act as its financial advisor. The special committee, with the assistance of its financial advisors, will consider and review the terms and conditions of any conversion and make a recommendation to the Board. There can be no assurance that the exploration of strategic alternatives will result in our conversion from a corporation into a master limited partnership.

Ongoing Acquisition and Disposition Activities

Consistent with our growth strategy, we are continuously engaged in discussions with potential sellers, including Lazarus Energy Holdings, LLC (“LEH”), our majority stockholder, regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. These acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only potential buyer or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets and operations which, if acquired, could have a material effect on our financial condition and results of operations and require special financing.

The closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts, including those described below, will be successful. Although we expect the acquisitions we make to be accretive in the long-term, we can provide no assurance that our expectations will ultimately be realized.

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

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

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

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Disposition of Working Interest in North Sumatra Basin. On November 6, 2012, we announced that Blue Dolphin Exploration Company (“BDEX”), a wholly-owned subsidiary, entered into a Sale and Purchase Agreement (the “Indonesia SPA”) with Blue Sky Langsa Limited (“Blue Sky”) for the disposal of its 7% undivided working interest in the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”) for approximately $800,000. As a result, our operations related to Indonesia ceased effective November 6, 2012 and the disposal was completed on February 28, 2013. We have reflected the results of Indonesia as discontinued operations in the financial statements. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” for additional disclosures regarding Indonesia and discontinued operations.

Management of Blue Dolphin’s Assets. In connection with our acquisition of LE, we entered into a Management Agreement with LEH (the “Management Agreement”) pursuant to which LEH manages and operates the Nixon Facility and Blue Dolphin’s other operations (collectively, the “Services”). Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 bpd processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We also agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month.

The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and GELTex Marketing, LLC (“GEL”) dated August 12, 2011(the “Joint Marketing Agreement”), which has an initial term of three years and year-to-year renewals at the option of either party thereafter, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by the Board and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

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Our Refinery

The Nixon Facility is a crude oil and condensate processing facility that has a current operating capacity of approximately 15,000 bpd. The Nixon Facility had no operations during 2011. The Nixon Facility can produce products such as Non-Road Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil. Currently, the Nixon Facility is operated as a “topping unit,” processing light crude oil and condensate from south Texas, including the Eagle Ford Shale formation, into NRLM for sale into nearby markets and naphtha and atmospheric gas oil for sale to nearby refineries for further processing.

The Nixon Facility is located on a 56-acre site in Nixon, Wilson County, Texas, and consists of a distillation unit, naphtha stabilizer, recovery facilities with approximately 120,000 barrels of crude oil storage capacity and 148,000 barrels of refined product storage capacity, as well as related loading and unloading facilities and utilities. Currently we purchase crude oil and condensate under a supply agreement with GEL, an affiliate of Genesis Energy, LLC (“Genesis”). We currently receive our feedstock by truck, however, the Nixon Facility also has the ability to receive crude oil and condensate via pipeline. Our refined products are currently sold and delivered by truck and barge. The following table sets forth historical information about production at our Nixon Facility since it was returned to service in February 2012:

	Year Ended December 31, 2012
Nixon Facility
Crude oil throughput capacity	15,000 bpd
Total feedstock runs(1)	3,175,283 bbls
Total refinery production	3,116,649 bbls

(1)   Total feedstock runs represents the barrels of crude oil and other feedstocks processed.

Pipeline Operations

Our pipeline operations, which represented less than 1% of total revenue for the twelve months ended December 31, 2012, 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. We charge producers and shippers a fee based on anticipated throughput volumes. All of our pipeline assets are held by and the business conducted by Blue Dolphin Pipe Line Company. Unless otherwise stated herein, all natural gas liquid volumes transported are attributable to production from third-party producers/shippers.

Pipeline Assets. The following provides a summary of our pipeline assets at December 31, 2012:

Pipeline Segment	Market	Ownership			Miles of Pipeline		Capacity (MMcf/d)
BDPS	U.S. Gulf of Mexico		83.3	%		38		180
GA 350	U.S. Gulf of Mexico		83.3	%		13		65
Omega	U.S. Gulf of Mexico		83.3	%		18		110

●   Blue Dolphin Pipeline System (“BDPS”) – The BDPS spans approximately 38 miles and runs from a junction platform in Galveston Area Block 288 offshore (“GA-288”) to our onshore facilities in Freeport, Texas (the “Freeport Plant”) and then to the Dow Chemical Plant Complex also in Freeport, Texas. For oil production, we handle offshore transportation. Onshore transportation, facilities services (such as storage) and sale are handled by a third-party. For natural gas production, we handle offshore and onshore transportation, facilities services (such as separation and dehydration) and sale of the natural gas to Dow Chemical Company.The BDPS has an aggregate capacity of approximately 180 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. The average throughput on the BDPS for the twelve months ended December 31, 2012 was 3.0 MMcf of gas per day, which represented 1.3% of throughput capacity, compared to average throughput of 4.4 MMcf of gas per day, which represented 2.0% of throughput capacity for the twelve months ended December 31, 2011.   The BDPS includes: (i) approximately 193 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the Freeport Plant, pipeline easements and rights-of-way are located, (ii) the offshore junction platform in GA-288 and (iii) the 20-inch Blue Dolphin Pipeline. The BDPS gathers and transports oil and natural gas from various offshore fields in the Galveston Area of the U.S. Gulf of Mexico to our Freeport Plant.

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●   Galveston Area Block 350 Pipeline (the “GA 350”) – The GA 350 is an 8-inch, 13 mile offshore pipeline extending from Galveston Area Block 350 to a point of terminus with a third-party transmission pipeline in Galveston Area Block 391, which is located approximately 14 miles south of the BDPS. For oil and natural gas production, we handle offshore transportation through the GA-350 to the third-party transmission pipeline. Current system capacity on the GA 350 is 65 MMcf of gas per day. The average throughput on the GA 350 for the twelve months ended December 31, 2012 was 16.5 MMcf of gas per day, which represented 25.4% of throughput capacity, compared to average throughput of 13.6 MMcf of gas per day, which represented 20.9% of throughput capacity for the twelve months ended December 31, 2011.

●   Omega Pipeline (the “Omega”) – The Omega originates in the High Island Area, East Addition Block A-173 and extends to West Cameron Block 342, where it was previously connected to the High Island Offshore System. The Omega is currently inactive. Reactivation of the Omega is dependent upon future drilling activity in the vicinity and successfully attracting producer/shippers to the system.

Exploration and Production

Our oil and gas exploration and production activities, which include leasehold interests in properties located in the U.S. Gulf of Mexico, were uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012. Our U.S. Gulf of Mexico oil and gas properties were fully impaired for the twelve months ended December 31, 2011.  See “Part I, Item 1. Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basin” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

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Exploration and Production Assets. The following provides a summary of our oil and gas properties at December 31, 2012:

Field	Operator	Interest
U.S. Gulf of Mexico:
High Island Block 115	Rooster Petroleum, LLC	2.5% WI, 2.008% NRI
Galveston Area Block 321	Black Elk Energy Offshore Operations LLC	0.5% ORRI
High Island Block 37	EPL Oil & Gas, Inc.	2.88% WI, 2.246% NRI

● High Island Block 115 – High Island Block 115 is located approximately 30 miles southeast of Bolivar Peninsula in an average water depth of approximately 38 feet. The B-1 ST2 Well was shut-in in early November 2012 to undergo wellhead repairs. The wellhead was not holding adequate pressure to meet federal regulatory standards. Work on the wellhead is estimated to occur in the first quarter of 2013.

● Galveston Area Block 321 – Galveston Area Block 321 is located approximately 32 miles southeast of Galveston in an average water depth of approximately 66 feet. The A-4 Well is currently shut-in. The well had no oil production in 2012 and last produced gas in September 2012. In December 2012, the operator did a recompletion of the well; the recompletion was not successful.  The operator has indicated plans to relinquish the lease in the first quarter of 2013.

● High Island Block 37 – High Island Block 37 is located approximately 15 miles south of Sabine Pass in an average water depth of approximately 36 feet. The block contains no active wells. The operator’s lease in the block expired in February 2012. At lease expiration, the operator indicated plans to plug and abandon the B-1 Well, remove the B-structure and temporary abandon the A-2 Well within one year of the lease expiration date. In October 2012, the operator assigned its interest in the block to another operator. The new operator completed temporary abandonment of the A-2 Well in January 2013. There has been no further indication of plans related to the B-1 Well.

Productive Wells and Acreage. The following table sets forth our ownership interest at December 31, 2012 in productive oil and natural wells in the areas indicated. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells reflect the total number of producing wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working or royalty interest. Productive wells consist of producing wells and wells capable of production.

	Oil				Natural Gas				Total
	Gross		Net		Gross		Net		Gross		Net
U.S. Gulf of Mexico
Working Interest		-		-		1.0		0.1		1.0		0.1
Overriding Royalty Interest		-		-		1.0		-		1.0		-
		-		-		2.0		0.1		2.0		0.1

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The following table sets forth the approximate developed and undeveloped acreage that we held as leasehold interest at December 31, 2012. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves.

	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
U.S. Gulf of Mexico		17,280		264		-		-		17,280		264
		17,280		264		-		-		17,280		264

Production, Price and Cost Data. The following table presents information regarding production volumes and revenue, average sales prices and costs (after deduction of royalties and interests of others) with respect to crude oil, condensate and natural gas attributable to our interests in the Gulf of Mexico for each of the periods indicated.

	Years Ended December 31,
	2012		2011
Crude Oil and Condensate:
Production (Bbls)		11		-
Revenue	$	1,087		-
Average production per day (Bbls) (*)		0.3		-
Average sales price per Bbl	$	98.82		-
Natural Gas:
Production (Mcf)		11,594		-
Revenue	$	27,272		-
Average production per day (Mcf) (*)		31.8		-
Average sales price per Mcf	$	2.35		-
Production Costs (**):
Per Mcfe:	$	-		-

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(*) Average production is based on a 365 day year.

(**) Production costs, exclusive of work-over costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes.

Drilling, Exploration and Development Activity. During the twelve months ended 2012, Black Elk Energy Offshore Operations LLC, operator of the Galveston Area Block 321 A-4 Well, did a recompletion of the well. The recompletion was not successful. During 2011, there was no drilling, exploration or development activity associated with our oil and gas leasehold interests.

Other Assets

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

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Raw Material Supply

The single input for our refinery is crude oil and condensate. In August 2011, we and GEL entered into the Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”).

The Crude Supply Agreement provides that we will exclusively obtain all of the crude oil for our Nixon Facility through GEL, other than the crude oil purchased from any other supplier with the prior consent of GEL. All crude oil supplied pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, we have granted GEL right of first refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement.

The Crude Supply Agreement has an initial term of three years and expires on August 12, 2014, subject to certain termination rights. Following the initial term, the Crude Supply Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 90 days prior to expiration of the initial Term or any renewal term.

Customers

Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. For the twelve months ended December 31, 2012, our four largest customers accounted for approximately 84% of our refined petroleum products sales.

Markets and Competition

The petroleum refining and marketing industry continues to be highly competitive. Many of our principal competitors are integrated, multi-national oil companies (e.g., Valero, Chevron, ExxonMobil, Shell and ConocoPhillips) and other major independent refining and marketing entities that operate in our market areas. The principal competitive factors affecting us are crude oil and other feedstock costs, refinery efficiency, operating costs, refinery product mix and product distribution/transportation costs.  Because of their diversity, integration of operations and larger capitalization, these competitors may be better able to withstand volatile market conditions, compete on the basis of price, obtain crude oil in times of shortage and bear the economic risk inherent in all phases of the refining industry due to their geographic diversity, operational complexity and resources.

We operate primarily in the Eagle Ford Shale in South Texas supplying refined petroleum products to the area from our Nixon Facility. The market for our refined products is generally supplied by a number of refiners, including large integrated oil companies or independent refiners. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.

Intellectual Property

We rely on intellectual property laws to protect our brand, as well as those of our subsidiaries. “Blue Dolphin” is a registered trademark in the U.S. in name and logo form. “Petroport” is a registered trademark in the U.S. in name form. In addition, www.blue-dolphin.com and www.blue-dolphin-energy.com are registered domain names.

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Employees

Pursuant to the Management Agreement, all Blue Dolphin subsidiaries are managed by LEH and all personnel work directly for LEH. LEH is reimbursed for providing personnel services under the Management Agreement.

Governmental Regulation

All of our operations and properties are subject to extensive and complex federal, state, and local environmental, health, and safety statutes, regulations, and ordinances governing, among other things, the generation, storage, handling, use and transportation of petroleum, solid wastes, hazardous wastes, and hazardous substances; the emission and discharge of materials into the environment and environmental protection; waste management; characteristics and composition of diesel and other fuels; and the monitoring, reporting and control of greenhouse gas emissions. These laws impose certain obligations on our operations, including requiring the acquisition of permits and authorizations to conduct regulated activities, restricting the manner in which regulated activities are conducted, limiting the quantities and types of materials that may be released into the environment, and requiring the monitoring of releases of materials into the environment.

Failure to comply with environmental, health or safety laws and our permits or other authorizations issued under such laws could result in fines, civil or criminal penalties or other sanctions, injunctive relief compelling the installation of additional controls, or a revocation of our permits and the shutdown of our facilities.

We cannot predict the extent to which additional environmental, health, and safety laws will be enacted in the future, or how existing or future laws will be interpreted with respect to our operations. Many environmental, health, and safety laws and regulations are becoming increasingly stringent. The cost of compliance with and governmental enforcement of environmental, health, and safety laws may increase in the future. We may be required to make significant capital expenditures or incur increased operating costs to achieve compliance with applicable environmental, health, and safety laws.

The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 (the “Energy Acts of 2005 and 2007”). Pursuant to the Energy Acts of 2005 and 2007, the Environmental Protection Agency (the “EPA”) issued Renewable Fuels Standards (“RFS”) that mandate the blending of renewable fuels into refined petroleum fuel products. The Nixon Facility is currently not subject to this requirement. However, on an annual basis, the EPA establishes new volume requirements and associated percentage standards that subject refineries to RFS. The volume requirements and associated percentage standards increase through 2022, when all facilities will be subject to the requirements.

The Federal Clean Air Act (the “CAA”). The CAA, its amendments and implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect our crude oil and condensate processing operations and impact certain emissions sources located offshore. Under the CAA, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations. The EPA has, in the past, targeted petroleum refineries as part of a nationwide enforcement initiative, and refineries remain high-visibility targets for enforcement under the CAA. In 1992, the EPA published a list of source categories (industry groups) that emit one or more of a list of 188 hazardous air pollutants (HAPs), also known as air toxics. The list of industry groups includes petroleum refineries because they are considered to be a major source of HAP emissions. The EPA developed standards that require the application of maximum achievable control technology (“MACT”) to help control HAP emissions. The Petroleum Refinery MACT standard applies to petroleum refining process units and related emission points. We are required to obtain permits, as well as to test, monitor, report and implement control requirements. In addition, our operations are subject to a number of New Source Performance Standards (“NSPS”) regulations. For example, in September 2012, the EPA issued final revisions to the NSPS for process heaters and flares at petroleum refineries. The final NSPS regulate emissions of nitrogen oxide from process heaters and emissions of sulfur dioxide from flares. The final rule also establishes work practice and monitoring standards for flares. In addition, air permits incorporating stringent control technology requirements are required for our refining operations that result in the emission of regulated air contaminants.

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The CAA also authorizes the EPA to require modifications in the formulation of refined fuel products. In 2007, the EPA issued a second Mobile Source Air Toxics standard (the “MSAT II”) that required significant reductions in the sulfur content in gasoline and diesel fuel. These standards required most refineries to reduce the sulfur content in diesel to 15 ppm and gasoline to 30 ppm. Low sulfur (500 ppm) and Ultra Low Sulfur Diesel (ULSD) fuel is expected to be phased in for NRLM engines in 2014. When implemented for NLRM, the MSAT II requirements may require us to undergo additional permitting and/or incur capital expenditures to meet the new requirements. We do not currently manufacture gasoline.

In 2007 the U.S. Supreme Court held in Massachusetts v. EPA that greenhouse gas emissions may be regulated as an air pollutant under the CAA. In December 2009, the EPA published a finding that greenhouse gas emissions present an endangerment to human health and the environment because emissions of such gasses are contributing to changes in climate. The EPA has since issued regulations that require a reduction in emissions of greenhouse gases from motor vehicles and that require greenhouse gas emission permits for certain sources. Specifically, the EPA has adopted regulations under existing provisions of the CAA establishing Prevention of Significant Deterioration (“PSD”) construction and Title V operation permits requiring reviews for greenhouse gasses for certain large, stationary sources. In September 2009 EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources, including refineries. In addition, pursuant to a December 23, 2010 settlement agreement EPA was required to propose by December 10, 2011, NSPS for greenhouse gas emissions from refineries and to finalize such rules by November 15, 2012. To date, however, EPA has not initiated that rulemaking. Future greenhouse gas regulations could impose significant costs on our operations and could affect the market for our products.

In addition to new greenhouse gas regulations, Congress has from time to time considered legislation to reduce greenhouse gas emissions. Almost one-half of the states have already taken measures to reduce greenhouse gas emissions through the establishment of greenhouse gas emission inventories and regional cap-and-trade programs. The adoption of future legislation limiting greenhouse gas emissions could cause us to incur additional compliance costs and may affect the demand for our products.

Occupational Safety and Health Administration (“OSHA”). In 2007, OSHA launched the National Emphasis Program for Petroleum Refineries (“RNEP”). The RNEP requires inspections of all refineries for compliance with process safety management regulations. Under the directive, our crude oil and condensate processing assets are subject to inspections that can continue two to six months, including one to three months on-site. Inspectors focus on checking process safety management implementation and records targeting specific process units and strategically sampling equipment, records and personnel. All of our operations are subject to OSHA’s standards for safe and healthful working conditions for personnel.

The Federal Water Pollution Control Act, also known as the Clean Water Act (the “CWA”). The CWA and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants, including spills and leaks of oil and other substances, into the water. The CWA and analogous state laws affect our crude oil and condensate processing operations, petroleum storage and terminaling operations, pipeline operations and exploration and production activities. The CWA prohibits the discharge of pollutants to waters of the United States except as authorized by the terms of a permit issued by the EPA or a state agency with delegated authority. Spill prevention, control, and countermeasure (“SPCC”) requirements mandate the use of structures, such as berms and other secondary containment, to prevent hydrocarbons or other pollutants from reaching a jurisdictional water in the event of a spill or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA or analogous state laws and regulations.

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The Oil Pollution Act of 1990 (the “OPA”). The OPA and regulations promulgated thereunder include a variety of requirements related to the prevention of oil spills and impose liability for damages resulting from such spills. OPA imposes liability on owners and operators of onshore and offshore facilities and pipelines for removal costs and certain public and private damages arising from a spill. OPA establishes a liability limit for onshore facilities of $350 million and offshore facilities of $75 million plus all clean-up costs. OPA establishes lesser liability limits for vessels depending upon their size. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction or operating regulations. If a party fails to report a spill or cooperate in the clean-up, liability limits do not apply. OPA imposes ongoing requirements on responsible parties, including proof of financial responsibility for potential spills. In October 1996, the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324), which amended OPA to establish requirements for evidence of financial responsibility for certain offshore facilities. The evidence of financial responsibility amount required is $35 million for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. We currently maintain the statutory $35 million coverage. While our financial responsibility requirements under OPA may be amended to impose additional costs, we do not expect the impact of such a change to be any more burdensome on us than on others similarly situated.

Outer Continental Shelf Lands Act (the “OCSLA”). Our pipeline operations and exploration and production activities within federal waters are subject to the requirements of OCSLA, which is administered by the Bureau of Ocean Energy Management (the “BOEM”) and the Bureau of Safety and Environmental Enforcement (the “BSEE”). BSEE oversees offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies. BSEE is responsible for safety and environmental oversight of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production, inspections, offshore regulatory programs and oil spill response compliance.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA imposes liability, without regard to fault or the legality of the original conduct, on parties the statute defines as responsible for the release or threatened release of a “hazardous substance” into the environment. Responsible parties, which include the present owner or operator of a site where the release occurred, the owner or operator of the site at the time of disposal of the hazardous substance and persons that disposed of or arranged for the disposal of a hazardous substance, are liable for response and remediation costs and for damages to natural resources. Petroleum and natural gas are excluded from the definition of hazardous substances; however, this exclusion does not apply to all materials used in our operations. State statutes impose similar liability. At this time, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA or similar state statute.

The Federal Resource Conservation and Recovery Act ( “RCRA”). RCRA and its state counterparts regulate solid and hazardous wastes and impose civil and criminal penalties for improper handling and disposal of such wastes. EPA and various state agencies have promulgated regulations that limit the disposal options for such wastes. Certain wastes generated by our oil and gas operations are currently exempt from regulation as hazardous wastes, but are subject to non-hazardous waste regulations. In the future these wastes could be designated as hazardous wastes under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements.

We currently own or lease, or have in the past owned or leased, various properties used for the crude oil and processing assets, petroleum storage and terminaling assets, pipeline assets and oil and gas leasehold interests used to process and store solid and hazardous wastes. Although our past operating and disposal practices at these properties were standard for the industry at the time, hydrocarbons or other substances may have been disposed of or released on or under these properties or on or under other locations. In addition, many of these properties have been operated by third parties whose waste handling activities were not under our control. These properties and any waste disposed thereon may be subject to CERCLA, RCRA, and state laws which could require us to remove or remediate wastes and other contamination or to perform remedial plugging operations to prevent future contamination.

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Environmental

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (22) Commitments and Contingencies” of this report for a description of our environmental activities.

Available Information

The SEC maintains and makes available public records, which includes reports filed by regulated companies and individuals, through conventional and electronic reading rooms. The SEC’s conventional reading room is located at 100 F Street, Northeast, Washington, D.C. 20549 and can be reached at (202) 551-8300. The SEC’s electronic reading room, which maintains records created by the SEC on or after November 1, 1996, is available online at http://www.sec.gov/foia/efoiapg.htm. Reports filed with the SEC by regulated entities and individuals are available at http://www.sec.gov/edgar/searchedgar/webusers.htm. We make our public filings available on our website (http://www.blue-dolphin-energy.com) as soon as reasonably practicable after such material is filed, or furnished, to the SEC. A copy of our filings will also be furnished free of charge upon request.

Information about each of our directors, our Audit Committee Charter and our code of conduct and code of ethics are available on our website. Information contained on our website is not part of this report.

Glossary of Industry Terms

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry.

Atmospheric Gas Oil. The heaviest product boiled by a crude distillation unit operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. In-blends atmospheric gas oil, often abbreviated AGO, usually serves as the premium quality component used to lift lesser streams to the standards of saleable furnace oil or diesel engine fuel. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock.

Back-in After Payout Interest.A contractual right of a non-participating partner to participate in a well or wells after the wells have produced enough for the participating partners to recover their capital costs of drilling, completing and operating the wells.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

Blending. The physical mixture of a number of different liquid hydrocarbons to produce a finished product with certain desired characteristics. Products can be blended in-line through a manifold system, or batch blended in tanks and vessels. In-line blending of gasoline, distillates, jet fuel and kerosene is accomplished by injecting proportionate amounts of each component into the main stream where turbulence promotes thorough mixing. Additives, including octane enhancers, metal deactivators, anti-oxidants, anti-knock agents, gum and rust inhibitors, and detergents, are added during and/or after blending to result in specifically desired properties not inherent in hydrocarbons.

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Bpd. Barrel per day.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate. Hydrocarbons that are in a gaseous state under reservoir conditions and become liquid when temperature or pressure is reduced; a mixture of pentanes and higher hydrocarbons.

Cooling Tower. A structure that cools heated refining process water by circulating the water through a series of louvers and baffles through which cool air is forced by large fans.

Crude Oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. Crude oil must be broken down into its various components by distillation before these chemicals and compounds can be used as fuels or converted to more valuable products. There are primarily five types of crude – West Texas Intermediate (“WTI”), Light Crude, Sweet Crude, Sour Crude and Brent Crude. See definitions of WTI, Light Crude, Sweet Crude and Sour Crude.

Crude Unit. The refinery processing unit where initial crude oil distillation takes place. See definition of Topping Unit.

Cut. One or more crude oil compounds that vaporize and are extracted within a certain temperature range during the crude distillation process.

Depropanizer. A distillation column that is used to isolate propane from a mixture containing butane and other heavy components.

Desalting. Removal of salt from crude oil. Desalting is preferably performed prior to commercialization of the crude; must be performed prior to refining.

Development Well. A well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Distillate. The liquid that has been condensed from vapor during distillation; normally a purified form or a fraction of an original liquid.

Distillation. The first step in the refining process. During distillation, crude oil is heated in the base of a distillation tower. As the temperature increases, the crude's various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower according to their densities. They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities.

Distillation Tower. A tall column-like vessel in which crude oil is heated and its vaporized components distilled by means of distillation trays.

Exploratory Well. A well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir or to extend a known reservoir.

Exchanger (Heat Exchanger). A device used to transfer heat from one process liquid to another.

Feedstocks. Processed oil destined for further processing other than blending. It is transformed into one or more components and/or finished products.

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Fractionation. The separation of crude oil into its more valuable and usable components through distillation.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Heat Exchanger. See definition for Exchanger.

Jet Fuel. A type of aviation fuel. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.

Kerosene. A thin, clear liquid formed from hydrocarbons. Obtained from the fractional distillation of petroleum between 150 °C and 275 °C, resulting in a mixture of carbon chains that typically contain between 6 and 16 carbon atoms per molecule.

Leasehold Interest. The interest of a lessee under an oil and gas lease.

Light Crude. Crude oil with a low wax content.

Liquefied Petroleum Gas (“LPG”).  Manufactured during the refining of crude oil. LPG burns relatively cleanly with no soot and very few sulfur emissions.

Mbbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or gas liquids.

MMbtu. One million British Thermal Units.

MMcf.One million cubic feet of gas.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Naphtha. A broad term covering among the lightest and most volatile fractions of the liquid hydrocarbons in petroleum. Naphtha is a colorless to reddish-brown volatile aromatic liquid, very similar to gasoline.

Net Revenue Interest. The percentage of production to which the owner of a working interest is entitled.

Non-operating Working Interest. A working interest, or a fraction of a working interest, in a lease where the owner is not the operator of the lease.

Non-Road, Locomotive and Marine Diesel Fuel (“NRLM”).  Commonly referred to as “off-road diesel.” Used in diesel engines for construction, agricultural, stationary engine, locomotive and marine operations. Off-road diesel has a higher sulfur content than on-road diesel.

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Overriding Royalty Interest. An interest in oil and gas produced at the surface, free of the expense of production that is in addition to the usual royalty interest reserved to the lessor in an oil and gas lease.

Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil.

Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquefied petroleum gases. The others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. See definition of Liquefied Petroleum Gas.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of oil, gas or both.

Proved Developed Reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved developed reserves are further categorized into two sub-categories -- proved developed producing reserves and proved developed non-producing reserves.

Proved Developed Producing.Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate.

Proved Developed Non-producing.Reserves sub-categorized as non-producing, which include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from: (i) completion intervals which are open at the time of the estimate but which have not started producing, (ii) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (iii) wells not capable of producing for mechanical reasons.

Proved Reserves. The estimated quantities of oil, gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves are further categorized into two sub-categories – proved developed and proved undeveloped depending on their development and production status.

Proved Undeveloped Reserves.Reserves that are expected to be recovered from new wells or from existing wells where a relatively significant expenditure is required for recompletion.

Recommissioning. While commissioning of a new plant facility or refinery helps ensure correct operation of its major systems when first installed, recommissioning helps to restore an existing plant facility or refinery to its originally intended operating performance. Both processes comprises the integrated application of a set of engineering techniques and procedures to check, inspect and test every operational component of the project, from individual functions, such as instruments and equipment, up to complex amalgamations such as modules, subsystems and systems.

Refined Petroleum Products. Refined petroleum products are derived from crude oils that have been processed through various refining methods. The resulting products include gasoline, home heating oil, jet fuel, diesel, lubricants and the raw materials for fertilizer, chemicals and pharmaceuticals. Following the refining process, the products are transported to terminals or local distribution centers for sale to various end-users and consumers.

Refinery. A plant where crude oil is separated and transformed into marketable refined petroleum products.

Separation. The separation of the different hydrocarbons present in crude oil depending on their respective boiling ranges. This process takes place in a distillation column.

Sour Crude. Crude oil containing sulfur content of more than 0.5%.Usually processed into heavy oil such as diesel.

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Stabilizer. A distillation column intended to remove the lighter boiling compounds, such as butane or propane from a product.

Sweet Crude. Crude oil containing sulfur content of less than 0.5%.Commonly used for processing into gasoline.

Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal or natural gas. Also produced as a byproduct of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized according to their sulfur content, with lower sulfur fuels usually selling at a higher, premium price and higher sulfur fuels selling at a lower, or discounted, price.

Topping Unit (Atmospheric Distillation). Conducts the initial transformation of crude oil at a refinery. The topping unit heats crude oil at atmospheric pressure to accomplish the first rough distillation cut. Lighter products produced in this process can be further refined in a catalytic cracking unit or reforming unit. Heavier products, which cannot be vaporized and separated in this process, can be further distilled in a vacuum distillation unit or coker.

Turnaround. Scheduled large-scale maintenance activity wherein an entire process unit is taken offline for a week or more for comprehensive revamp and renewal.

Ultra-low-sulfur Diesel (“ULSD”)(On-Road Diesel). Diesel fuel with substantially lowered sulfur content (currently 15 ppm). Primarily used as commercial transportation fuel.

Undivided Interest. A form of ownership interest in which more than one person concurrently owns an interest in the same oil and gas lease or pipeline.

West Texas Intermediate (“WTI”). A grade of crude oil used as a benchmark in oil pricing. Described as intermediate because of its relative mid-range density and mid-range sulfur content.

Working Interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production after the corresponding percentage of operational costs and royalties are paid.

ITEM 1A.  RISK FACTORS

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks we face. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.

Risks Related to our Business

Genesis’ hedging on our refined petroleum products may limit our gains and expose us to other risks.

We are exposed to market price risk related to our refined petroleum products 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, NLRM 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.

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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 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.

Our operations are highly dependent on our relationship with Genesis, and, if we are unable to successfully maintain this relationship, our operations, liquidity and financial condition will be harmed.

We are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil, transportation of crude oil, provision of accounting and other services, joint marketing of our refined petroleum products and funding of renovations, expansion and other capital expenditures relating to the Nixon Facility. Further, we have an understanding with Genesis relating to an inventory risk management system, which is intended to reduce the commodity price risk of our finished products inventory and generate a more consistent gross margin for each barrel of refined product. These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain this relationship or our relationship is not on good terms, we believe that it could have a material adverse effect on our operations, liquidity and financial condition.

We are currently in default under certain of our long-term debt and are operating under forbearance agreements. Our failure to comply with provisions contained in the forbearance agreements, including as a result of events beyond our control, could materially and adversely affect our operating results and our financial condition.

We cannot assure that our assets or cash flow would be sufficient to fully repay borrowings under our outstanding notes payable, either upon maturity or if accelerated, or that we would be able to refinance or restructure the payments on the notes payable. If we fail to comply with provisions contained in the forbearance agreements, then the senior lender may exercise any rights and remedies available under the loan agreement and applicable law including, without limitation, foreclosing on our assets. Any such action by our senior secured lender would have a material adverse effect on our financial condition and ability to continue as a going concern.

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

Historically, we have used a portion of our cash reserves to fund our working capital requirements that were not funded from our operations.  Most recently, we have relied on advances under the Construction Funding Agreement and revenue from operations, including sales of refined products and rental of storage tanks, to fund our working capital requirements.  Currently we expect that these resources will be sufficient to satisfy our anticipated working capital requirements over the next 12 – 18 months.  If we cannot generate sufficient cash flows from operations, continue to make advances under the Construction and Funding Agreement or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to repayment of the Refinery Loan.  Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades at the Nixon Facility.  In addition, from time to time, we expect to utilize significant capital to upgrade equipment, improve facilities and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.

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Our primary source of crude oil supply experiences significant price swings, which impacts our crude oil acquisition cost.

The Nixon Facility is located in the heart of the Eagle Ford Shale play, an abundant source of domestic petroleum production. The gathering infrastructure in this area is developing such that, occasionally, large inventories of local crude oil may be transported in bulk away from the Nixon Facility. When this occurs, we may experience wider than normal swings in crude oil prices in order to obtain our desired levels of crude oil.

We depend exclusively on GEL for our supply of crude oil and other feedstocks, and the loss of GEL or a material decrease in the supply of crude oil and other feedstocks generally available to the Nixon Facility could have a material adverse effect on our operations and financial condition.

We purchase 100% of our crude oil and other feedstocks exclusively from GEL under the Crude Supply Agreement. We cannot purchase crude oil or other feedstock from another supplier without the consent of GEL. We are dependent on GEL and the loss of GEL would adversely affect our financial results to the extent we were unable to find another supplier of crude oil.

To the extent that GEL reduces the volumes of crude oil and other feedstocks that they supply us as a result of declining production or competition or otherwise, our sales, net income and cash available for payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply the Nixon Facility, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers. A material decrease in either the crude oil production from or the drilling activity in the fields that supply the Nixon Facility, as a result of depressed commodity prices, natural production declines, governmental moratoriums on drilling or production activities, the availability and the cost of capital or otherwise, could result in a decline in the volume of crude oil we refine.

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, cash flows and liquidity.

Our refining earnings, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase earnings, it is important to maximize the yields of finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, diesel, and other refined products. Such supply and demand are affected by, among other things:

●   changes in global and local economic conditions;

●   domestic and foreign demand for fuel products, especially in the United States, China and India;

●   worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;

●   the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported into the United States;

●   availability of and access to transportation infrastructure;

●   utilization rates of U.S. refineries;

●   the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;

●   development and marketing of alternative and competing fuels;

●   commodities speculation;

●   natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;

●   federal and state government regulations and taxes; and

●   local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

Loss of market share with or by a key customer, or consolidation among our customer base, could harm our operating results.

For the twelve months ended December 31, 2012, a large percentage of our revenue, 84%, came from sales to four customers. These customers have a variety of suppliers to choose from and therefore can make substantial demands on us, including demands on product pricing and on contractual terms, which often results in the allocation of risk to us as the supplier. Our ability to maintain strong relationships with our principal customers is essential to our future performance. If we lose a key customer, if any of our key customers reduce their orders of our refined petroleum products or require us to reduce our prices before we are able to reduce costs, if a customer is acquired by one of our competitors or if a key customer suffers financial hardship, our operating results could likely be harmed.

Additionally, if there is consolidation among our customer base, our customers may be able to command increased leverage in negotiating prices and other terms of sale, which could adversely affect our profitability. In addition, if, as a result of increased leverage, customer pressures require us to reduce our pricing such that our gross margins are diminished, we could decide not to sell our refined petroleum products to a particular customer, which could result in a decrease in our revenue. Consolidation among our customer base may also lead to reduced demand for our products, replacement of our products by the combined entity with those of our competitors and cancellations of orders, each of which could harm our operating results.

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Refining margins are volatile, and a reduction in anticipated refining margins will adversely affect the amount of cash we will have available for working capital.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our specialty products prices and the prices for crude oil. The cost to acquire crude oil and the price at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control.

The prices at which we sell specialty products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our specialty products segment margins will fall unless we are able to pass along these price increases to our wholesale customers. Increases in selling prices for specialty products typically lag the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period of time.

The sale of refined petroleum products to the wholesale market is an important part of our business going forward, and if we fail to grow and maintain our market share or gain market acceptance of our refined petroleum products, our operating results could suffer.

Selling refined petroleum products to the wholesale market is an important part of our business, and as our refined petroleum products revenue increases as a portion of our overall revenue, our success in the wholesale market becomes increasingly important to our operating results. Our success in the wholesale market depends in large part on our ability to grow and maintain our image and reputation as an independent operator and to expand into and gain market acceptance of our refined petroleum products. Adverse perceptions of product quality, whether or not justified, or allegations of product quality issues, even if false or unfounded, could tarnish our reputation and cause our wholesale customers to choose refined petroleum products offered by our competitors.

We are dependent on third-party operators for the transportation of crude oil into and refined petroleum products out of our Nixon Facility, and if these third-party operators become unavailable to us, our ability to process crude oil and sell refined petroleum products to wholesale markets could be materially and adversely affected.

We rely on trucks for the receipt of crude oil into and the sale of refined petroleum products out of our Nixon Facility. Since we do not own or operate any of these trucks, their continuing operation is not within our control. If any of the third-party trucking companies that we use, or the trucking industry in general, become unavailable to transport crude oil or our refined petroleum products because of acts of God, accidents, government regulation, terrorism or other events, our revenue and net income would be materially and adversely affected.

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Potential downtime for maintenance at the Nixon Facility could reduce our revenue and cash available for payments of our obligations.

Although currently operating at anticipated levels, the Nixon Facility is still in a recommissioning phase and may require additional unscheduled downtime for unanticipated maintenance or repairs. Any scheduled or unscheduled maintenance reduces our revenues and increases our operating expenses during the period of time that our processing unit is not operating and could reduce our ability to meet our payment obligations.

LEH holds a significant interest in us and our related party transactions with LEH and its affiliates may cause conflicts of interest that may adversely affect us.

Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, and Tommy L. Byrd, our interim Chief Financial Officer, Treasurer and Assistant Secretary, are also a member and employee, respectively, of LEH and as a result may, under certain circumstances, have interests that differ from or conflict with our interests. Further, pursuant to the Management Agreement, LEH manages and operates the Nixon Facility and Blue Dolphin’s other operations. As a result of their relationship with LEH, Messrs. Carroll and Byrd may experience conflicts of interest in the execution of their duties on behalf of Blue Dolphin including with respect to the Management Agreement.

LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock. Through its ownership of such a large amount of Common Stock, LEH has significant influence over matters such as the election of our Board, control over our business, policies and affairs and other matters submitted to our stockholders. LEH is entitled to vote the Common Stock it owns in accordance with its interests, which may be contrary to our interests and those of other stockholders. LEH has interests that differ from the interests of our stockholders and, as a result, there is a risk that important business decisions will not be made in the best interest of our stockholders. LEH and its other affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities. We believe that the transactions and agreements that we have entered into with LEH and its affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties. However, these relationships could create, or appear to create, potential conflicts of interest when our Board is faced with decisions that could have different implications for us and LEH or its affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which may have a material adverse effect on our ability to do business.

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The geographic concentration of our refinery and other assets creates a significant exposure to the risks of the local economy and other local adverse conditions. The location of our refinery also creates the risk of significantly increased transportation costs should the supply/demand balance change in our region such that regional supply exceeds regional demand for refined products.

As our refinery and other assets are located in the Eagle Ford Shale and Gulf Coast area of Texas, we primarily market our refined and retail products in a single, relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenue. These factors include, among other things, changes in the economy, weather conditions, demographics and population.

Should the supply/demand balance shift in our region as a result of changes in the local economy as discussed above, an increase in refining capacity or other reasons, resulting in supply in the PADD III region of the EIA exceeding demand, we would have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any. Changes in market conditions could have a material adverse effect on our business, financial condition and results of operations.

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Competition from companies having greater financial and other resources than we do could materially and adversely affect our business and results of operations.

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in the PADD III region of the United States as defined by the EIA, as well as with domestic refiners in other PADD regions and foreign refiners that import products into the United States. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain all of our feedstocks from a single source. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.  If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.

We may not be able to successfully execute our strategy of growth within the refining industry through acquisitions.

A component of our growth strategy is to selectively consider accretive acquisitions within the refining industry based on sustainable performance of the targeted assets through the refining cycle, access to advantageous crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure and potential operating synergies. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:

●   diversion of management time and attention from our existing business;

●   challenges in managing the increased scope, geographic diversity and complexity of operations;

●   difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;

●   liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;

●   greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results;

●   difficulties in achieving anticipated operational improvements; and

●   incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities and reduce our liquidity. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our facilities, any of which could result in production and distribution difficulties and disruptions, pollution (such as oil spills, etc.), personal injury or wrongful death claims and other damage to our properties and the property of others.

There is also risk of mechanical failure and equipment shutdowns both in the normal course of operations and following unforeseen events. In such situations, undamaged refinery processing units may be dependent on, or interact with, damaged process units and, accordingly, are also subject to being shut down. Because all of our refining operations are conducted at a single refinery, any such event(s) at our refinery could significantly disrupt our production and distribution of refined products. Any sustained disruption would have a material adverse effect on our business, financial condition, results of operations and cash flows.  Additionally, our offshore operations are also subject to a variety of operating risks exclusive to the marine environment such as hurricanes or other adverse weather conditions and restrictive governmental regulation.  These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.

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Our refineries, terminals and related facility operations and other operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.

Our refinery, terminals and related facility operations and other assets are subject to certain operating hazards, and our cash flow from those operations could decline if any of our facilities experiences a major accident, pipeline rupture or spill, explosion or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. These operating hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in significant curtailment or suspension of our related operations.

Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent, we cannot ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or significant interruption of operations. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for environmental accidents at all of our facilities.

Our business requires the retention and recruitment of a skilled workforce and the loss of key employees could result in the failure to implement our business plan.

The success of our business operations depends largely upon the efforts of key executive officers and technical personnel. Given our small size, we may not be able to retain required personnel on acceptable terms due to the competition for experienced personnel from other companies in the industry.

We may incur significant liability under, or costs and capital expenditures to comply with, environmental, health and safety regulations, which are complex and change frequently.

Our refinery, pipelines and other operations are subject to federal, state and local laws regulating, 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 matters otherwise relating to the protection of the environment. Our operations are also subject to various laws and regulations relating to occupational health and safety. Compliance with the complex array of federal, state and local laws relating to the protection of the environment, health and safety is difficult and likely will require us to make significant expenditures. Moreover, our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances into the environment including at neighboring areas or third-party storage, treatment or disposal facilities. Certain environmental laws impose joint and several liability without regard to fault or the legality of the original conduct in connection with the investigation and cleanup of such spills, discharges or releases. As such, we may be required to pay more than our fair share of such investigation or cleanup. We may not be able to operate in compliance with all applicable environmental, health and safety laws, regulations and permits at all times. Violations of applicable legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or facility shutdowns. We may also be required to make significant capital expenditures or incur increased operating costs or change operations to achieve compliance with applicable standards.

We cannot predict the extent to which additional environmental, health and safety legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA published final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries to be effective November 13, 2012. These amendments include standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We continue to evaluate the regulation and amended standards, as may be applicable to the operations at our refinery. We cannot currently predict what costs that we may have to incur, if any, to comply with the amended NSPS, but the costs could be material. Expenditures or costs for environmental, health and safety compliance could have a material adverse effect on our results of operations, financial condition and profitability and, as a result, our ability to make distributions.

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In 2014, new environmental regulations become effective that reduce the allowable sulfur content for commercially sold diesel in the United States. Unless the Nixon Facility undergoes significant capital upgrades, we may be limited to selling “off specification” diesel at lower prices.

New environmental regulations will become effective in 2014 that reduce the sulfur content that is permitted to be contained in diesel sold commercially in the United States. In order to meet the higher content standards, the Nixon Facility may require capital upgrades in excess of approximately $50 million. In order to complete the required capital upgrades, we will have to finance such capital expenditures primarily through the issuance of debt and/or equity, which would result in dilution to existing stockholders and/or subject us to higher debt levels. There can be no assurance that we can obtain such financing at rates or at terms acceptable to us, if at all.

Regulation of greenhouse gas emissions could increase our operational costs and reduce demand for our products.

Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on our operations and financial results.

International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, our activities in the particular jurisdiction and market conditions. Greenhouse gas emissions that could be regulated include those arising from the conversion of crude oil into refined petroleum products, the transportation of crude oil and natural gas, and the exploration and production of crude oil and natural gas. Some matters related to these activities, such as actions taken by our competitors in response to such laws and regulations, are beyond our control.

The effect of regulation on our financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which we would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits and the impact of legislation or other regulation on our ability to recover the costs incurred through the pricing of our products. Material price increases or incentives to conserve or use alternative energy sources could also reduce demand for products we currently sell and adversely affect our sales volumes, revenues and margins.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

We lease office space in Houston, Texas, which serves as our company headquarters. LEH operates our owned plant facilities in Nixon, Wilson County, Texas and Freeport, Brazoria County, Texas. LEH is reimbursed for the management and operation of these facilities under the Management Agreement.

See “Part I, Item 1. Business – Exploration and Production” of this report for information regarding our oil and gas leasehold interests. Such information is incorporated herein by reference.

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ITEM 3.  LEGAL PROCEEDINGS

Pursuant to a Settlement Agreement and Mutual Release by and among Blue Dolphin, LEH and Lazarus Louisiana Refinery II, LLC (“LLRII”) effective February 15, 2012, the parties agreed to settle and compromise all disputes between them in connection with closing of the LE Acquisition. LEH agreed to file a non-suit with prejudice of all pending claims against Blue Dolphin under Cause No. 210-32561, styled Blue Dolphin Energy Company v. Lazarus Energy Holdings, L.L.C. and Lazarus Louisiana Refinery II, L.L.C., in the 129th District Court of Harris County, Texas (the “Lawsuit”). Blue Dolphin agreed that it will not execute or attempt to execute on an order that was signed on May 16, 2011 in the Lawsuit severing LEH’s counterclaims into Cause No. 2010-32561-A, which resulted in a Partial Summary Judgment becoming a final judgment in Blue Dolphin’s favor. Pursuant to an Order of Nonsuit and Dismissal with Prejudice, a presiding judge ordered, adjudged and decreed that counter-plaintiff LEH’s claims and causes of action in the Lawsuit were dismissed on July 6, 2012.

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. During the twelve months ended December 31, 2012, a vendor placed a mechanic’s lien on the Nixon Facility as protection during construction activities. Management does not believe that the lien will have a material adverse effect on our results of operations.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

Remainder of Page Intentionally Left Blank

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Common Stock is quoted on the OTCQX U.S. Premier tier under the ticker symbol “BDCO.” The following table sets forth, for the periods indicated, the high and low prices for our Common Stock as reported by the Nasdaq and the OTC Markets. The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.

Quarter Ended	High		Low
2012
December 31	$	6.50	$	3.85
September 30	$	7.95	$	6.01
June 30	$	9.22	$	6.18
March 31	$	11.60	$	4.28
2011(1)
December 31	$	2.88	$	1.70
September 30	$	3.64	$	0.99
June 30	$	4.90	$	1.33
March 31	$	3.71	$	2.24
______________
(1)  Between June 13, 2011 and September 1, 2011, our Common Stock traded on the OTCQB.

Simultaneous with the delisting of our Common Stock from the Nasdaq Capital Market on February 28, 2012, our Common Stock began trading on the OTCQX U.S. Premier tier of the OTC Markets under the ticker symbol “BDCO."

Holders

As of March 29, 2013, we had 287 record holders of our Common Stock. We have approximately 3,000 beneficial holders of our Common Stock.

Dividends

We have not declared or paid any dividends on our Common Stock since our incorporation.  We currently intend to retain earnings for our capital needs and expansion of our business and do not anticipate paying cash dividends on the Common Stock in the foreseeable future. We expect that any loan agreements we enter into in the future will likely contain restrictions on the payment of dividends on our Common Stock. Future policy with respect to dividends will be determined by the Board based upon our earnings and financial condition, capital requirements and other considerations. We are a holding company that conducts substantially all of our operations through our subsidiaries. As a result, our ability to pay dividends on the Common Stock will also be dependent upon the cash flow of our subsidiaries.

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ITEM 6.  SELECTED FINANCIAL DATA

Not applicable.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a review of certain aspects of our financial condition and results of operations and should be read in conjunction with “Part I, Item 1. Business” and “Part II, Item 8. Financial Statements and Supplementary Data” including the associated “Notes to Consolidated Financial Statements” of this report.

Executive Summary

In February 2012, we acquired LE, which owned the Nixon Facility. Historically, we were engaged in two lines of business: (i) pipeline transportation services to producers/shippers and (ii) oil and gas exploration and production. As a result of the acquisition of LE our primary business is the refining of crude oil into marketable finished and refined products such as Non-Road, Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), naphtha and atmospheric gas oil. As part of our refining business, we also conduct petroleum storage and terminaling operations under third party lease agreements at the Nixon Facility. We also continue to own and operate pipeline assets and have leasehold interests in oil and gas properties.

Under applicable accounting rules LE, although a subsidiary of Blue Dolphin, was treated as the accounting parent and Blue Dolphin was treated as the accounting subsidiary. Accordingly, the financial statements after the date of the acquisition of LE are presented as a continuation of LE. The Nixon Facility, LE's primary asset, was returned to service in February 2012 and had no operations during 2011.

The acquisition of LE represents a fundamental change in our business. Increases in our revenue, operating expenses and other related costs are primarily attributable to our refining operations.

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Operational Highlights

Operational highlights for our core business segment, refinery operations, follows:

Current Year

Refinery Operations Operated a total of 326 days; average throughput was approximately 9,700 bpd, or 65% of operating capacity (the Nixon Facility began operations in February 2012).

Petroleum Storage and Terminaling 85,000 bbls of tankage under lease agreement.

Prior Year

Refinery Operations The Nixon Facility had no operations during the prior year.

Petroleum Storage and Terminaling 20,000 bbls of tankage under lease agreement.

Major Influences on Results of Operations

Earnings and cash flow from our refining operations are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined petroleum products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products, which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, which affect our earnings.

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

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

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Safety, reliability and the environmental performance of the Nixon Facility is critical to our financial performance. The financial impact of a turnaround or major maintenance project is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined petroleum products are essentially commodities, and we have no control over the changing market value of these inventories. In May 2012 we implemented 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.

Relationship with Genesis

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

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

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

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

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

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. After the expiration of its initial term, the Crude Supply Agreement automatically renews for successive one year terms unless either party notifies the other party of its election to terminate the Crude Supply Agreement within 90 days of the expiration of the then current term.

● Construction and Funding Agreement -- Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam has continued to make advances in excess of their obligation, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made. The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement for a breach or upon termination of the Refinery Loan Forbearance Agreement. If Milam terminates the Construction and Funding Agreement, then: (i) Milam and LE are required to execute a forbearance agreement, the form of which has been previously agreed to, pursuant to which LE will pay Milam a fee of $150,000 per month in order to maintain the forbearance (such amount shall be credited against the amount owed) for a period of six months (during which time Milam will agree not to foreclose pursuant to the Construction and Funding Agreement and, thus, LE has the right to find financing to pay off such amounts), (ii) Milam shall be entitled to receive payment in full for all obligations owed under the Construction and Funding Agreement, (iii) all liens in favor of Milam will remain in full force and effect until released in accordance with the terms of the Construction and Funding Agreement and (iv) upon repayment of all obligations owed to Milam pursuant to the terms of the forbearance agreement executed by Milam and LE, LE shall have no further obligations to Milam or its affiliates under the Construction and Funding Agreement;

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

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

(b)	Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.
(c)	Third, prior to the Investment Threshold Date and subject to the payment of the Base Construction Payment by LE and the Operations Payments by GEL, pursuant to (a) and (b) above, an amount shall be paid to GEL from Gross Profits equal to transportation costs, tank storage fees (if applicable), financial statement preparation fees (collectively, the “GEL Expense Items”), after which GEL shall be paid 80% of the remaining Gross Profits (any percentage of Gross Profits distributed to GEL, the “GEL Profit Share”) and LE shall be paid 20% of the remaining Gross Profits (any percentage of Gross Profits distributed to LE, the “LE Profit Share”); provided, however, that in the event that there is a forbearance payment of Gross Profits required by LE under a forbearance agreement with a bank, then 50% of the LE Profit Share shall be directly remitted by GEL to the bank on LE’s behalf until such forbearance amount is paid in full; and provided further that, if there is a Deficit Amount due under the Construction and Funding Agreement and a forbearance payment of Gross Profits that would otherwise be due and payable to the bank for such period, then GEL shall receive 80% of the Gross Profit and 10% shall be payable to the bank and LE shall not receive any of the LE Profit Share until such time as the Deficit Amount is reduced to zero.
(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.

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

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. After the expiration of its initial term, the Joint Marketing Agreement shall be automatically renewed for successive one year terms unless either party notifies the other party of its election to terminate the Joint Marketing Agreement within 90 days of the expiration of the then current term. The Joint Marketing Agreement also provides that it may be terminated prior to the end of its then current term under certain circumstances.

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

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

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

As of December 31, 2012, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,206,175. As of December 31, 2012, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $659,883.

As of December 31, 2012, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the twelve months ended December 31, 2012, payments made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits were approximately $287,091.

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Results of Operations

Twelve Months Ended December 31, 2012 (the "Current Year") Compared to Twelve Months Ended December 31, 2011 (the "Prior Year")

Summary. For the current year we reported a loss from continuing operations, net of tax, of $13,841,066, or a loss of $1.35 per share, on total revenue from operations of $352,094,714. We reported a loss from discontinued operations, net of tax, of $4,443,566, or a loss of $0.43 per share, for the current year. For the prior year, we reported an income from continuing operations, net of tax, of $183,854, or income of $0.02 per share. We had no discontinued operations in the prior year. Under reverse acquisition accounting, the financial statements subsequent to the date of the LE Acquisition are presented as the continuation of LE. Accordingly, Blue Dolphin’s previously reported income and expenses for the prior year are not reflected and instead are the financial results of LE.

Total Revenue from Operations. Substantially all of our revenue came from refined product sales, which generated revenue of $351,665,234, or 99% of total revenue from operations, in the current year. The Nixon Facility had no revenue from operations in 2011.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $342,035,755 for the current year compared to $0 for the prior year. The Nixon Facility had no costs from operations in 2011.

Refinery Operating Expenses. We recorded Nixon Facility operating expenses of $8,603,155 in the current year, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH. See “Part II, Item 8. Financial Statements and Supplementary Data - Note (15), Accounts Payable, Related Party” and "Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions" of this report for additional disclosures related to the Management Agreement. The Nixon Facility had no expenses from operations in 2011.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $391,169 in the current year compared to $0 in the prior year.

Lease Operating Expenses. Lease operating expenses totaled $57,122 in the current year compared to $0 in the prior year.

General and Administrative Expenses. General and administrative expenses increased from $645,444 in the prior year to $2,076,946 in the current year. The expenses in the current year were primarily related to leased corporate personnel costs, as well as consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization increased from $17,684 in the prior year to $1,622,864 in the current year primarily as a result of the Nixon Facility having operations in the current year compared to having no operations in the prior year.

Abandonment Expense. We recognized $1,184,549 of abandonment expense in the current year related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount expensed reflected the amount incurred in the current year less the amount reserved for the asset retirement obligation liability, which was $141,099.  There was no comparable expense in 2011.

Impairment. Due to the continued weakness in our pipeline transportation and oil and gas exploration production business segments and the uncertainty of the timing and speed of recovery, we recorded an impairment of $9,435,745 in the current year. Management currently has no future plans to expand pipeline operations given current market conditions. Therefore an impairment of the pipeline was deemed necessary for the current year. The impairment charge in the current year consisted of $7,990,025 related to our pipeline fixed assets and $1,445,720 related to goodwill, 100% of which was associated with our pipeline transportation and oil and gas exploration production business segments. We recorded $0 in impairment charges in 2011. See “Intangibles – Goodwill and Other” and “Recently Adopted Accounting Guidance” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information related to goodwill, other intangible assets, impairment of goodwill and impairment of long-lived assets.

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Other Income. We recognized $534,047 in net tank rental revenue in the current year compared to $874,421 in the prior year.

Discontinued Operations, Net of Tax. In November 2012, BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. In connection with the Indonesia SPA, we adjusted the value of our oil and gas interest in Indonesia to $800,000, which resulted in an impairment charge of $3,858,427 in the current year. We also recorded an allowance for doubtful accounts receivable of $321,732 in the current year associated with non-payment of accounts receivable for our proportionate share of crude oil liftings revenue due from Blue Sky for Indonesia. Operations associated with Indonesia were reclassified as discontinued operations in the current year. See “Part I, Item 1. Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basin” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

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

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

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Following is a reconciliation of EBITDA by business segment for the twelve months ended December 31, 2012 (and at December 31, 2012) and the twelve months ended December 31, 2011 (and at December 31, 2011):

	Twelve Months Ended December 31, 2012
	Segment
						Oil and Gas
	Refinery		Pipeline			Exploration &			Corporate &
	Operations		Transportation			Production			Other(1)			Total
Revenue	$	351,665,234	$	406,812		$	22,668		$	-		$	352,094,714
Operation cost(2)	$	350,940,269	$	8,676,242		$	2,018,126		$	2,270,009			363,904,646
Other non-interest income	$	534,047		-			-			-			534,047
EBITDA	$	1,259,012	$	(8,269,430	)	$	(1,995,458	)	$	(2,270,009	)	$	(11,275,885	)
Depletion, depreciation and amortization													(1,622,864	)
Other income (expense), net													(932,639	)
Loss from continuing operations, before income taxes												$	(13,831,388	)
Loss from discontinued operations												$	(4,443,566	)
Capital expenditures	$	2,852,460	$	-		$	-		$	-		$	2,852,460
Identifiable assets(3)	$	52,745,767	$	1,861,055		$	48,247		$	1,726,854		$	56,381,926

	Twelve Months Ended December 31, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenue	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		645,444		-		-		-		645,444
Other non-interest income		874,421		-		-		-		874,421
EBITDA	$	228,977	$	-	$	-	$	-	$	228,977
Depletion, depreciation and amortization										(17,684	)
Other income (expense), net										(27,439	)
Income from continuing operations before income taxes									$	183,854
Capital expenditures	$	3,507,850	$	-	$	-	$	-	$	3,507,850
Identifiable assets(3)	$	38,144,056	$	-	$	-	$	-	$	38,144,056

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

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Critical Accounting Policies

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

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

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

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

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

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

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Impairment of Long Lived Assets. Our policy is to assess the realizability of our long-lived assets, including intangible assets, and to evaluate such assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets (or group of assets) may not be recoverable. Impairment is determined to exist if the estimated future undiscounted cash flows are less than the carrying value. Future cash flow projections include assumptions for future pipeline throughput levels, anticipated capital expenditures and the impact of cost reduction measures and the level of working capital needed to support each business. Any difference between the estimated fair value and the carrying value of the asset is recognized as an impairment. For the years ended December 31, 2012 we recognized an impairment of $7,990,025 related to our pipeline fixed assets.

Recently Adopted Accounting Guidance

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

Liquidity and Capital Resources

Sources and Uses of Cash. At December 31, 2012, our available cash was $420,896.

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2012			2011			2012			2011
Cash flow from operations
Adjusted income (loss) from continuing operations	$	2,736,327		$	(50,549	)	$	(1,831,753	)	$	224,869
Adjusted loss from discontinued operations		(435,460	)					(435,460	)
Change in current assets and liabilities		811,739			(349,995	)		2,334,540			27,414
Total cash flow from operations		3,112,606			(400,544	)		67,327			252,283
Cash inflows (outflows)
Proceeds from issuance of debt		-			2,851,992			4,788,623			3,304,300
Payments on long-term debt		(2,563,062	)		(10,688	)		(3,276,748	)		(42,610	)
Cash acquired on acquisition		115			-			1,674,709			-
Proceeds from exercise of stock options		20,000			-			20,000			-
Capital expenditures		(284,011	)		(2,440,292	)		(2,852,460	)		(3,507,850	)
Proceeds from notes payable		-			-			24,548			-
Payments on note payble		(4,025	)		-			(26,925	)		(5,034	)
Total cash inflows (outflows)		(2,830,983	)		401,012			351,747			(251,194	)
Total change in cash flows	$	281,623		$	468		$	419,074		$	1,089

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

For the current year, we experienced positive cash flow from operations of $67,327.  For the three months ended December 31, 2012, we experienced positive cash flow from operations of $3,112,606. This represents an increase compared to negative cash flow from operations of $28,017 for the third quarter of 2012, negative cash flow from operations of $1,438,903 for the second quarter of 2012 and negative cash flow from operations of $1,578,359 for the first quarter of 2012. Our liquidity improvement quarter over quarter was primarily the result of higher product sales margins.

During the current year, we took key steps towards improving our liquidity, as follows:

(a) Improve and Generate More Consistent Margins Through Better Inventory Risk Management. We implemented an inventory risk management policy in the second quarter of 2012 wherein 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). This policy helped stabilize our commodity price exposure for our refined petroleum products and crude oil inventory, which enabled us to generate a more consistent gross margin for each barrel of refined product. Our refining margins were relatively stable throughout the current year, allowing the Nixon Facility to generate an EBITDA of $1,259,012 for the current year. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Earnings Before Interest, Income Taxes and Depreciation” of this report for a reconciliation of EBITDA by business segment.

(b) Increase the Amount of Throughput Generated by the Nixon facility. A significant part of our business strategy is to move towards operating the Nixon Facility at or near capacity in the first half of 2013. For the current year, average throughput increased to approximately 9,700 bpd, or 65% of operating capacity. To further increase throughput, we intend to progressively ramp up throughput levels, and, on a longer-term basis, complete refurbishment of the naphtha stabilizer. See Item (c) below for additional discussion related to the naphtha stabilizer.

(c) Focus on Capital Expenditure Program to Increase Throughput and Improve Margins. We estimate costs to complete refurbishment of the naphtha stabilizer, as well as a depropanizer unit, at the Nixon Facility to be approximately $1.5 million. Refurbishment of the naphtha stabilizer and depropanizer will improve the quality of naphtha that we produce and increase the amount of throughput that can be processed by the Nixon Facility. Our ability to complete this capital expenditure project is dependent upon further advances being made by Milam under the Construction and Funding Agreement, cash from operations or third-party financing. There can be no assurance that funding will be obtained for completion of this capital expenditure project.

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.

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Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Our U.S. Gulf of Mexico oil and gas properties were fully impaired for the twelve months ended December 31, 2011. On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012.  See “Part I, Item 1, Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basis,” as well as “Part II, Item 8. Financial Statements and Supplementary Data - Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

We recognized $1,184,549 of abandonment expense in the current year related to plugging and abandonment costs associated with our High Island A-7 oil and gas leasehold interest. The amount recognized reflects the amount incurred in the current year less the amount reserved for the asset retirement obligation liability, which was $141,099. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

We received proceeds from the issuance of debt in the current year of $4,788,623, primarily under the Construction and Funding Agreement. Capital expenditures in the current year totaled $2,852,460, all of which related to refurbishment of the Nixon Facility. We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $5,206,175 and $3,319,193, including Deficit Amounts, at December 31, 2012 and 2011, respectively.

The principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183 and $9,669,173 at December 31, 2012 and 2011, respectively. As of the date of the filing of this report, the Refinery Loan is subject to a forbearance agreement (the "Forbearance Agreement").

As of December 31, 2102, past due principal and interest (as well as costs, fees and taxes) was $250,070. After all past due principal and interest has been paid AFNB has agreed to: (i) re-amortize the Refinery Loan to the original maturity date of October 1, 2028 and (ii) apply twelve consecutive additional monthly payments in the amount of $83,333.33 towards replenishing the $1.0 million payment reserve required under the Refinery Loan in accordance with the Forbearance Agreement.

The principal balance outstanding on the Notre Dame Debt note, which is currently in default, was $1,300,000 at December 31, 2012 and 2011. There are no financial covenants associated with this debt.

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (20) Long-Term Debt” of this report for additional disclosures related to our long-term debt obligations.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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.

At December 31, 2012, we performed a sensitivity analysis to determine the impact of an increase in the market price of commodity contracts for our economic hedges. Based on this sensitivity analysis, we determined that an increase of $1.00 per barrel in commodity contracts held at December 31, 2012 would increase unrealized loss by approximately $30,000.

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 December 31, 2012, we had $9,298,183 of variable interest debt with a weighted average interest rate at year end of approximately 5.50%. At December 31, 2012, 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 December 31, 2012 would increase interest expense by approximately $92,982 per year.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	45
Consolidated Balance Sheets at December 31, 2012 and 2011	46
Consolidated Statements of Operations for the Twelve Months Ended December 31, 2012 and 2011	47
Consolidated Statements of Stockholders’ Equity for the Twelve Months Ended December 31, 2012 and 2011	48
Consolidated Statements of Cash Flows for the Twelve Months Ended December 31, 2012 and 2011	49
Notes to Consolidated Financial Statements	50

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Report of Independent Registered Public Accounting Firm

The Board of Directors and

Stockholders of Blue Dolphin Energy Company

We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and its subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and its subsidiaries as of December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

UHY LLP

Sterling Heights, Michigan

April 1, 2013

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BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

	December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	420,896		$	1,822
Restricted cash		89,593			192,004
Accounts receivable, net		15,398,755			-
Prepaid expenses and other current assets		228,314			58,713
Deposits		1,236,447			473,026
Inventory		2,300,692			4,533,961
Total current assets		19,674,697			5,259,526
Property, plant and equipment, net		35,862,085			32,307,929
Debt issue costs, net		532,335			566,133
Other assets		9,463			10,468
Trade name		303,346			-
TOTAL ASSETS	$	56,381,926		$	38,144,056
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	19,171,013		$	4,841,859
Accounts payable, related party		1,594,021			908,139
Note payable		43,941			46,318
Accrued expenses and other current liabilities		725,238			744,921
Interest payable, current portion		640,352			995,916
Long-term debt, current portion		1,816,960			1,839,501
Total current liabilities		23,991,525			9,376,654
Long-term liabilities:
Asset retirement obligations		921,260			-
Long-term debt, net of current portion		13,989,517			12,455,102
Long-term interest payable, net of current portion		858,784			650,214
Total long-term liabilities		15,769,561			13,105,316
TOTAL LIABILITIES		39,761,086			22,481,970
Commitments and contingencies
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,563,297 and 8,426,456		105,633			84,265
shares issued and outstanding at December 31, 2012 and December 31, 2011, respectively)
Additional paid-in capital		36,524,142			17,302,124
Accumulated deficit		(20,008,935	)		(1,724,303	)
Total stockholders' equity		16,620,840			15,662,086
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	56,381,926		$	38,144,056

See accompanying notes to condensed consolidated financial statements.

46

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

Consolidated Statements of Operations

	Twelve Months Ended December 31,
	2012			2011
REVENUE FROM OPERATIONS
Refined product sales	$	351,665,234		$	-
Pipeline operations		406,812			-
Oil and gas sales		22,668			-
Total revenue from operations		352,094,714			-
COST OF OPERATIONS
Cost of refined products sold		342,035,755			-
Refinery operating expenses		8,603,155			-
Pipeline operating expenses		391,169			-
Lease operating expenses		57,122			-
General and administrative expenses		2,076,946			645,444
Depletion, depreciation and amortization		1,622,864			17,684
Abandonment expense		1,184,549			-
Impairment expense		9,435,745			-
Bad debt expense		9,508			-
Accretion expense		105,032			-
Loss on disposal of property and equipment		5,665			-
Total cost of operations		365,527,510			663,128
Loss from operations		(13,432,796	)		(663,128	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		534,047			874,421
Interest and other income		21,940			23,901
Interest expense		(954,579	)		(51,340	)
Total other income (expense)		(398,592	)		846,982
Income (loss) from continuing operations before income taxes		(13,831,388	)		183,854
Tax expense
Current		(9,678	)		-
Deferred		-			-
Income tax expense		(9,678	)		-
Income (loss) from continuing operations, net of tax	$	(13,841,066	)	$	183,854
Loss from discontinued operations, net of tax	$	(4,443,566	)	$	-
Net income (loss)	$	(18,284,632	)	$	183,854
Basic earnings (loss) per common share
Continuing operations	$	(1.35	)	$	0.02
Discontinued operations	$	(0.43	)	$	-
Basic earnings (loss) per common share	$	(1.78	)	$	0.02
Diluted earnings (loss) per common share
Continuing operations	$	(1.35	)	$	0.02
Discontinued operations	$	(0.43	)	$	-
Diluted earnings (loss) per common share	$	(1.78	)	$	0.02
Weighted average number of common shares outstanding:
Basic		10,284,152			8,426,456
Diluted		10,284,152			8,426,456

See accompanying notes to condensed consolidated financial statements.

47

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity

	Common				Additional					Total
	Stock		Common		Paid-In		Accumulated			Stockholders’
	Shares		Stock		Capital		Deficit			Equity
Balance at December 31, 2010		8,426,456	$	84,265	$	17,302,124	$	(1,908,151	)	$	15,478,238
Net income		-		-		-		183,854			183,854
Balance at December 31, 2011		8,426,456		84,265		17,302,124		(1,724,303	)		15,662,086
Common stock issued for acquisition		2,098,390		20,984		18,025,170		-			18,046,154
Conversion of LE's related party accounts											-
payable to equity on acquisition		-		-		993,732		-			993,732
Common stock issued for services		30,288		303		183,197		-			183,500
Common stock issued to exercise options		8,163		81		19,919		-			20,000
Net loss		-		-		-		(18,284,632	)		(18,284,632	)
Balance at December 31, 2012		10,563,297	$	105,633	$	36,524,142	$	(20,008,935	)	$	16,620,840

Remainder of Page Intentionally Left Blank

48

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

Consolidated Statements of Cash Flows

	Twelve Months Ended December 31,
	2012			2011
OPERATING ACTIVITIES
Net income (loss)	$	(18,284,632	)	$	183,854
Loss from discontinued operations		4,443,566			-
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization		1,611,708			17,684
Impairment expense		9,435,745			-
Unrealized loss on derivatives		136,100			-
Amortization of debt issue costs		33,799			33,799
Amortization of intangible assets		10,468			(10,468	)
Accretion expense		105,032			-
Abandonment expense		503,454			-
Common stock issued for services		163,499			-
Bad debt expense		9,508			-
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
Restricted cash		102,411			33,797
Accounts receivable		(14,724,996	)		-
Prepaid expenses and other current assets		43,894			(58,712	)
Deposits		(763,421	)		(397,407	)
Inventory		2,288,436			(4,484,521	)
Accounts payable, accrued expenses and other liabilities		12,160,088			4,950,484
Accounts payable, related party		3,228,128			(16,227	)
Net cash provided by operating activities - continuing operations		502,787			252,283
Net cash used in operating activities - discontinued operations		(435,460	)		-
Net cash provided by operating activities		67,327			252,283
INVESTING ACTIVITIES
Capital expenditures		(2,852,460	)		(3,507,850	)
Cash acquired on acquisition		1,674,709			-
Net cash used in investing activities		(1,177,751	)		(3,507,850	)
FINANCING ACTIVITIES
Proceeds from issuance of debt		4,788,623			3,304,300
Payments on long term debt		(3,276,748	)		(42,610	)
Proceeds from notes payable		24,548			-
Payments on notes payable		(26,925	)		(5,034	)
Proceeds from excercse of stock options		20,000			-
Net cash provided by financing activities		1,529,498			3,256,656
Net increase in cash and cash equivalents		419,074			1,089
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,822			733
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	420,896		$	1,822
Supplemental Information:
Non-cash investing and financing activities:
Related party payable converted to equity	$	993,732		$	-
Issuance of stock for acquisition of Blue Dolphin at fair value, inclusive
of cash acquired of $1,674,709	$	18,046,154		$	-
Accrued services payable converted to common stock	$	183,500		$	-

See accompanying notes to consolidated financial statements.

49

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(1) Organization

Company Operations

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

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

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

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

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

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

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

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

Effective February 15, 2012, Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE from Lazarus Energy Holdings, LLC (“LEH”), a Delaware limited liability company (the “LE Acquisition”). The LE Acquisition was accounted for as a reverse merger using accounting principles applicable to reverse acquisitions whereby the financial statements subsequent to the date of the transaction are presented as a continuation of LE (the legal subsidiary). See “Note (4) LE Acquisition” of this report for further information related to the LE Acquisition.

 (2) Basis of Presentation

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

 (3) Significant Accounting Policies

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

Use of Estimates

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

50

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash

Restricted cash was $89,593 and $192,004 at December 31, 2012 and 2011, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. At December 31, 2012 and 2011, we had uninsured balances of $170,896 and $0, respectively.

We had 4 customers that accounted for approximately 84% of our total revenue for the twelve months ended December 31, 2012. These 4 customers represented approximately $11.4 million of accounts receivable at December 31, 2012.

Inventory

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

Price-Risk Management Activities

In May 2012, we implemented an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Accordingly, even though such hedge positions are direct contractual obligations of Genesis and not us, we nevertheless record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

51

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the years ended December 31, 2012 and 2011.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  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 uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Operations associated with Indonesia were discontinued in 2012. See “Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations. The estimated fair values of our AROs related to our oil and gas properties were recorded in connection with the LE Acquisition.

Pipelines and Facilities Assets. Pipelines and facilities assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded in connection with the LE Acquisition.

Construction in Progress. Construction in progress expenditures, insurance, interest and other costs related to refurbishment activities at the Nixon Facility are capitalized as incurred. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the Nixon Facility. Depreciation begins once the asset is placed in service.

Intangibles – Goodwill and Other

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

52

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

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

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

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

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

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

53

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Debt Issue Costs

We have debt issue costs related to certain of our long-term 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 exclusive of amortization were $675,980 at December 31, 2012 and 2011. Accumulated amortization in the amount of $143,645 and $109,847 at December 31, 2012 and 2011, respectively, are being amortized over the life of the Refinery Loan. Amortization expense, which is included in interest expense, was $8,450 for the years ended December 31, 2012 and 2011. Amortization expense was $25,349 for the years ended December 31, 2012 and 2011. See “Note (20) Long-Term Debt” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

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

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

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

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at December 31, 2012 was not material.

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

Income Taxes

We 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 (21) Income Taxes” for further details.

54

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

55

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Business Combinations

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

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

56

Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Recently Adopted Accounting Guidance

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

New Pronouncements Issued but Not Yet Effective

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

(4) LE Acquisition

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

LE owns a petroleum refinery located in Nixon, Wilson County, Texas (the “Nixon Facility”). The processing plant at the Nixon Facility is currently in a recommissioning phase and has not yet reached its full operational capacity. The tank farm has 120,000 barrels of crude oil storage capacity and 180,000 barrels of refined product storage capacity. The Nixon Facility has the capability to produce products such as Non-Road, Locomotive, and Marine Diesel Fuel (“NRLM”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil.

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

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

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

The below table summarizes the purchase price allocation of the net assets acquired and measurement period adjustments as of the acquisition date (as adjusted). The estimated fair values of the assets acquired and liabilities assumed were based on information that was available as of the acquisition date. Measurement period adjustments for Blue Dolphin were completed during 2012.

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

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

From the date of the LE Acquisition (February 15, 2012) through December 31, 2012, Blue Dolphin’s revenue and net loss from continuing operations included in the consolidated statements of operations for the twelve month period ended December 31, 2012, was $429,480 and $13,078,963, respectively.

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Supplemental Pro Forma Information

The following pro forma condensed consolidated statements of operations for the twelve months ended December 31, 2012 and 2011 consolidate the historical consolidated statements of operations of Blue Dolphin and LE giving effect to the LE Acquisition as if it had occurred on January 1, 2011. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only:

	Twelve Months Ended December 31, 2012
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$	-		$	351,665,234		$	351,665,234
Pipeline operations		446,236			-			446,236
Oil and gas sales		28,957			-			28,957
Total revenue from operations		475,193			351,665,234			352,140,427
COST OF OPERATIONS
Cost of refined products sold		-			342,035,755			342,035,755
Refinery operating expenses		-			8,603,155			8,603,155
Pipeline operating expenses		450,634			-			450,634
Lease operating expenses		66,122			-			66,122
Abandonment expense		1,184,549			-			1,184,549
Depletion, depreciation and amortization		571,164			1,082,124			1,653,288
Impairment of oil and gas properties		9,435,745			-			9,435,745
Bad debt expense		9,508			-			9,508
General and administrative expenses		1,954,196			295,694			2,249,890
Accretion expense		115,812			-			115,812
Gain on sale of property and equipment		-			5,665			5,665
Total cost of operations		13,787,730			352,022,393			365,810,123
Loss from operations		(13,312,537	)		(357,159	)		(13,669,696	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			534,047			534,047
Interest and other income		9,720			13,059			22,779
Interest expense		(2,529	)		(952,050	)		(954,579	)
Total other income (expense)		7,191			(404,944	)		(397,753	)
Loss before income taxes		(13,305,346	)		(762,103	)		(14,067,449	)
Income tax expense		(9,678	)		-			(9,678	)
Loss from continuing operations, net of tax		(13,315,024	)		(762,103	)		(14,077,127	)
Loss from discontinued operations, net of tax		(4,445,433	)		-			(4,445,433	)
Net loss	$	(17,760,457	)	$	(762,103	)	$	(18,522,560	)

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

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	Twelve Months Ended December 31, 2011
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Pipeline operations	$	931,500		$	-		$	931,500
Oil and gas sales		1,342,718			-			1,342,718
Total revenue from operations		2,274,218			-			2,274,218
COST OF OPERATIONS
Pipeline operating expenses		1,008,859			-			1,008,859
Lease operating expenses		1,174,252			-			1,174,252
Depletion, depreciation and amortization		591,927			17,684			609,611
General and administrative expenses		1,574,364			645,444			2,219,808
Accretion expense		131,690			-			131,690
Total cost of operations		4,733,798			663,128			5,396,926
Gain on sale of property and equipment		3,081,053			-			3,081,053
Income (loss) from operations		621,473			(663,128	)		(41,655	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			874,421			874,421
Interest and other income		17,383			23,901			41,284
Interest expense		-			(51,340	)		(51,340	)
Total other income		17,383			846,982			864,365
Income before income taxes		638,856			183,854			822,710
Income tax expense		(20,921	)		-			(20,921	)
Net income	$	617,935		$	183,854		$	801,789

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

(5) Lazarus Refining & Marketing, LLC (“LRM”) Acquisition

Effective October 1, 2012, we acquired 100% of the issued and outstanding membership interest of LRM, a Delaware limited liability company and a wholly-owned subsidiary of LEH pursuant to an Assignment Agreement. The acquisition was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of LRM were transferred at their carrying amounts at the date of transfer and the results of operations are included for the twelve months ended December 31, 2012. LRM did not have significant assets, liabilities or results of operations for the twelve months ended December 31, 2011. Assets and liabilities included in the consolidated balance sheets were $100,285 and $499,591, respectively, as of December 31, 2012. LRM markets petroleum storage and terminaling services at the Nixon Facility.

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(6) Business Segment Information

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

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

	Twelve Months Ended December 31, 2012
	Segment
						Oil and Gas
	Refinery		Pipeline			Exploration &			Corporate &
	Operations		Transportation			Production			Other(1)			Total
Revenue	$	351,665,234	$	406,812		$	22,668		$	-		$	352,094,714
Operation cost(2)	$	350,940,269	$	8,676,242		$	2,018,126		$	2,270,009			363,904,646
Other non-interest income	$	534,047		-			-			-			534,047
EBITDA	$	1,259,012	$	(8,269,430	)	$	(1,995,458	)	$	(2,270,009	)
Depletion, depreciation and
amortization													(1,622,864	)
Other income (expense), net													(932,639	)
Loss from continuing operations,
before income taxes												$	(13,831,388	)
Loss from discontinued operations												$	(4,443,566	)
Capital expenditures	$	2,852,460	$	-		$	-		$	-		$	2,852,460
Identifiable assets(3)	$	52,745,767	$	1,861,055		$	48,247		$	1,726,854		$	56,381,926

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of the economic hedges on our refined petroleum products, executed by Genesis, is included within operation cost of our Crude Oil and Condensate Processing group. Cost of refined products sold includes a realized loss of $90,507 and an unrealized gain of $136,100 for the twelve months ended December, 2012.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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Segment financials for the twelve months ended December 31, 2011 (and at December 31, 2011) were as follows:

	Twelve Months Ended December 31, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenue	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		645,444		-		-		-		645,444
Other non-interest income		874,421		-		-		-		874,421
EBITDA	$	228,977	$	-	$	-	$	-
Depletion, depreciation and
amortization										(17,684	)
Other income (expense), net										(27,439	)
Income from continuing operations
before income taxes									$	183,854
Capital expenditures	$	3,507,850	$	-	$	-	$	-	$	3,507,850
Identifiable assets(3)	$	38,144,056	$	-	$	-	$	-	$	38,144,056

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

(7) Fair Value Measurement

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

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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 December 31, 2012 and 2011 due to their short-term maturities. The fair value of our longer term debt for the twelve months ended December 31, 2012 and 2011 was $15,806,477 and $14,294,603, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and the basis for that measurement:

			Fair Value Measurement at December 31, 2012 Using
Financial assets:	Carrying Value as at December 31, 2012		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	$	136,100	$	136,100	$	-	$	-

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

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

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

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

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

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

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As of December 31, 2012, 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):	2012		2013		2014		2015
Refined petroleum products and crude oil -
net short (long) positions		30,000		-		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in the consolidated balance sheets at December 31, 2012 and 2011:

		Fair Value
		December 31,		December 31,
Liabilities Derivatives	Balance Sheets Location	2012		2011
	Accrued expenses and other
Commodity contracts	current liabilities	$	136,100	$	-

The following table provides the effect of derivative instruments on the consolidated statements of operations for the twelve months ended December 31, 2012 and 2011:

		Gain (Loss) Recognized
		December 31,			December 31,
Derivatives	Statements of Operations Location	2012			2011
Commodity contracts	Cost of refined products sold	$	(136,100	)	$	-

(9) Concentration of Risk

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2014.

Significant Customers. Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. For the twelve months ended December 31, 2012, our four largest customers accounted for approximately 84% of our refined petroleum products sales.

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

	December 31,			December 31,
	2012			2011
Low-sulfur diesel		48.7	%		-
Naphtha		26.2	%		-
Atmospheric gas oil		25.1	%		-
		100.0	%		-

(10) Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	December 31,		December 31,
	2012		2011
Prepaid insurance	$	185,814	$	27,100
Employee advances		22,500		25,083
Property insurance		-		3,741
Workers compensation insurance		-		2,789
Prepaid loan closing fees		20,000		-
	$	228,314	$	58,713

(11) Deposits

Deposit balances consisted of the following:

	December 31,		December 31,
	2012		2011
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		312,000
Purchase option deposits		283,421		-
Deposits	$	1,236,447	$	473,026

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(Continued)

(12) Inventories

Inventory balances consisted of the following:

	December 31,		December 31,
	2012		2011
Low-sulfur diesel	$	397,240	$	2,193,864
Naphtha		1,562,055		1,067,011
Atmospheric gas oil		322,356		1,010,877
Other liquids		-		64,486
Propane		-		59,599
Crude		19,041		134,289
Supplies		-		3,835
	$	2,300,692	$	4,533,961

(13) Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	December 31,		December 31,
	2012		2011
Refinery and facilities	$	34,000,199	$	-
Pipelines and facilities		1,233,811		-
Onshore separation and handling facilities		325,435		-
Land		577,965		104,740
Other property and equipment		577,567		217,136
		36,714,977		321,876
Less: Accumulated depletion, depreciation and amortization		1,674,151		62,443
		35,040,826		259,433
Construction in Progress		821,259		32,048,496
Property, Plant and Equipment, Net	$	35,862,085	$	32,307,929

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(14) Discontinued Operations

On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012. The operating results of the discontinued operations are summarized as follows:

	December 31,			December 31,
	2012			2011
Revenue	$	674,797		$	-
Lease operating expenses		788,525			-
Depletion, depreciation and amortization		124,811			-
Impairment expense		3,858,427			-
Bad debt expense		321,732			-
Accretion expense		24,868			-
Total costs and expenses		5,118,363			-
Loss from discontinued operations, net of tax	$	(4,443,566	)	$	-

(15) Accounts Payable, Related Party

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

Under the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and GELTex Marketing, LLC (“GEL”) dated August 12, 2011(the “Joint Marketing Agreement”), which has an initial term of three years and year-to-year renewals at the option of either party thereafter, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by our Board of Directors (the “Board”) and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

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Aggregate amounts expensed for Services at the Nixon Facility for the twelve months ended December 31, 2012 were $8,603,155 (approximately $2.71 per barrel). At December 31, 2012 and 2011, the amounts outstanding to LEH were $1,594,021 and $908,139, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets. LE related party payable was converted to LE’s members’ equity in the amount of $993,732 on the effective date of the LE Acquisition.

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

(16) Notes Payable

Notes payable at December 31, 2012 and 2011 was $43,941 and $46,318, respectively.

In January 2010, LE issued a $100,000 short-term note as payment for financing costs. The unsecured note, which bears interest at 18% and was originally due in January 2012, has been extended to June 2013. The balance on this note at December 31, 2012 and 2011 was $39,866 and $46,318, respectively.

In March 2012, LE acquired two used trucks for use at the Nixon Facility under a short-term note payable. The unsecured note bears interest at 5%. The balance on this note at December 31, 2012 was $4,075.

(17) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,		December 31,
	2012		2011
Storage lease	$	-	$	480,000
Excise taxes		292,303		-
Salaries		134,501		184,909
Transportation		69,551		-
Property taxes		-		37,171
Insurance		-		21,770
Unrealized hedging loss		136,100
Unearned revenue		92,783		21,071
	$	725,238	$	744,921

 

(18) Asset Retirement Obligations

Refinery and Facilities

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

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Oil and Gas Properties and Pipelines and Facilities Assets

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

	December 31,			December 31,
	2012			2011
Fair value of asset retirement obligations at February 15, 2012	$	1,294,139		$	-
Liabilities extinguished		(361,680	)		-
Liabilities settled		(141,099	)		-
Accretion expense from continuing operations		105,032			-
Accretion from discontinued operations		24,868			-
Asset retirement obligations as of December 31, 2012		921,260			-
Less: current portion of asset retirement obligations		-			-
Asset retirement obligations, long-term balance
at December 31, 2012	$	921,260		$	-

During the twelve months ended December 31, 2012, plugging and abandonment costs related to our High Island A-7 oil and gas property exceeded the amount reserved for the ARO liability. Accordingly, the excess amount, which was $1,184,549, was recognized as a loss during the period. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

(19) Impairment

Due to the continued weakness in our pipeline transportation and oil and gas exploration production business segments and the uncertainty of the timing and speed of recovery, we recorded an impairment of $9,435,745 for the twelve months ended December 31, 2012. The impairment charge in the period consisted of $1,445,720 related to goodwill, 100% of which was associated with our pipeline transportation and oil and gas exploration production business segments, and $7,990,025 related to our pipeline fixed assets.

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(20) Long-Term Debt

Our outstanding long-term debt obligations consist of notes payable, construction financing and capital leases and are as follows:

	December 31,		December 31,
	2012		2011
Refinery Loan	$	9,298,183	$	9,669,173
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		5,206,175		3,319,193
Captial Leases		2,119		6,237
		15,806,477		14,294,603
Less: Current portion of long-term debt		1,816,960		1,839,501
	$	13,989,517	$	12,455,102

The following is a schedule of future long-term debt payments:

Years Ending December 31,	Amount
2013	$	1,861,256
2014		1,972,878
2015		2,092,528
2016		718,292
2017		411,203
Subsequent to 2017		8,750,320
	$	15,806,477

Refinery Loan.  In September 2008, LE obtained a loan from First International Bank (“FIB”) in the amount of $10,000,000 (the “Refinery Loan”).  The Refinery Loan accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at December 31, 2012) and has a maturity date of October 2028.  The Refinery Loan is: (i) secured by a first lien on the Nixon Facility and general assets of LE and (ii) subject to certain restrictive financial covenants related to debt to net worth and current ratio.  Currently, we are not in compliance with certain financial covenants and, since August 2011, the Refinery Loan has been subject to a forbearance agreement (the “Forbearance Agreement”). Interest was accrued on the Refinery Loan in the amount of $250,070 and $967,567 at December 31, 2012 and 2011, respectively.

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

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

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

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

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

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

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(Continued)

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

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

Notre Dame Debt.  LE obtained a loan in the original amount of $8,000,000 from Notre Dame Investors, Inc., which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at the default rate of 16% and is secured by a subordinated lien on the Nixon Facility and general assets of LE.  Interest was accrued on the note in the amount of $858,784 and $650,214 at December 31, 2012 and 2011, respectively.  There are no financial covenants associated with the Notre Dame Debt.

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

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  Interest totaled $386,695 and $23,578 at December 31, 2012 and 2011, respectively.  There are no financial covenants associated with this obligation.

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(Continued)

See “Note (22) Commitments and Contingencies” of this report for additional disclosures related to amendments to the Joint Marketing Agreement, which previously added to our obligation amount under the Construction and Funding Agreement.

Capital Leases.  LE was obligated under various capital lease agreements for equipment totaling $2,119 and $6,237 at December 31, 2012 and 2011, respectively.  The capital leases require monthly payments ranging from $164 to $2,559, including imputed interest at rates ranging from 8.50% to 13.39%, and maturing at various dates through February 2014.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

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

	December 31,		December 31,
	2012		2011
Cost	$	9,396	$	9,396
Less: Accumulated amortization		4,541		3,602
	$	4,855	$	5,794

Remainder of Page Intentionally Left Blank

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(Continued)

(21) Income Taxes

LE is a limited liability company and, prior to the LE Acquisition, its taxable income or loss flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon LE's Acquisition, LE became the legal subsidiary of Blue Dolphin and LE’s taxable income or loss flows through to Blue Dolphin for federal and state income tax purposes. As a result of the LE Acquisition, Section 382 of the Internal Revenue Code imposes a limitation on the use Blue Dolphin’s NOLs. At December 31, 2012, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

Income tax expense was $9,678 for the twelve months ended December 31, 2012. Income tax expense related to state income tax.

The income tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2012 is presented below:

Deferred tax assets (liabilities):
Net operating loss and capital loss carryforwards	$	8,482,237
Start-up costs (Nixon Refinery)		1,922,708
Basis differences in property and equipment		(1,044,223	)
Other		312,826
Total deferred tax assets		9,673,548
Less: valuation allowance		(9,673,548	)
Deferred tax assets, net	$	-

In assessing the recoverability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. A full valuation allowance against our net deferred tax asset was recorded at December 31, 2012 due to our uncertainty as to the utilization of the deferred tax assets in the foreseeable future.

Our effective tax rate applicable to continuing operations in 2012 was as follows:

Expected tax rate	34.00	%
Permanent differences	(0.17	%)
State tax	(0.04	%)
Change in valuation allowance	(33.84	%)
	(0.05	%)

As a result of the LE Acquisition, Section 382 of the Internal Revenue code imposes potential limitations on the use of our net operating loss (“NOL”) carryovers. The amount of NOL subject to such limitations is approximately $18.5 million. The NOL generated subsequent to the LE Acquisition, approximately $6.4 million, is not subject to any such limitation. For the twelve months ended December 31, 2012, we did not recognize any deferred tax asset related to such NOL’s due to the uncertainty of its use.

We have adopted the provisions of the ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. 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. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

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(Continued)

The provisions of the guidance on accounting for uncertainty in income taxes have been applied to all of our material tax positions taken for all open tax years on the date of adoption through the fiscal year ended December 31, 2012. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the guidance.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the year ended December 31, 2012. Furthermore, none of our federal and state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. As of December 31, 2012, fiscal years 2009 and later remain subject to examination by the IRS and fiscal years 2008 and later remain subject to examination by State of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax. At December 31, 2012, we accrued $0 in TMT.

(22) Commitments and Contingencies

Management Agreement

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

Genesis Agreements

We are highly dependent on our relationship with Genesis and its affiliates. Our relationship with Genesis is governed by three agreements:

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. After the expiration of its initial term, the Crude Supply Agreement automatically renews for successive one year terms unless either party notifies the other party of its election to terminate the Crude Supply Agreement within 90 days of the expiration of the then current term.

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Notes to Consolidated Financial Statements

(Continued)

● Construction and Funding Agreement -- Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam has continued to make advances in excess of their obligation, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.   The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement for a breach or upon termination of the Refinery Loan Forbearance Agreement. If Milam terminates the Construction and Funding Agreement, then: (i) Milam and LE are required to execute a forbearance agreement, the form of which has been previously agreed to, pursuant to which LE will pay Milam a fee of $150,000 per month in order to maintain the forbearance (such amount shall be credited against the amount owed) for a period of six months (during which time Milam will agree not to foreclose pursuant to the Construction and Funding Agreement and, thus, LE has the right to find financing to pay off such amounts), (ii) Milam shall be entitled to receive payment in full for all obligations owed under the Construction and Funding Agreement, (iii) all liens in favor of Milam will remain in full force and effect until released in accordance with the terms of the Construction and Funding Agreement and (iv) upon repayment of all obligations owed to Milam pursuant to the terms of the forbearance agreement executed by Milam and LE, LE shall have no further obligations to Milam or its affiliates under the Construction and Funding Agreement;

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

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

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(Continued)

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

(c)

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

(d)

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

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

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. After the expiration of its initial term, the Joint Marketing Agreement shall be automatically renewed for successive one year terms unless either party notifies the other party of its election to terminate the Joint Marketing Agreement within 90 days of the expiration of the then current term. The Joint Marketing Agreement also provides that it may be terminated prior to the end of its then current term under certain circumstances.

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(Continued)

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

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

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

As of December 31, 2012, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,206,175. As of December 31, 2012, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $659,883.

As of December 31, 2012, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the twelve months ended December 31, 2012, payments made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits were approximately $287,091.

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

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

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

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Notes to Consolidated Financial Statements

(Continued)

Lazarus Energy Development, LLC (“LED”) Option

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

Legal Matters

Pursuant to a Settlement Agreement and Mutual Release dated February 15, 2012 (the “Settlement Agreement”), by and among Blue Dolphin, LEH and Lazarus Louisiana Refinery II, LLC (“LLRII”), the parties agreed to settle and compromise all disputes between them in connection with closing of the LE Acquisition. LEH agreed to file a non-suit with prejudice of all pending claims against Blue Dolphin under Cause No. 210-32561, styled Blue Dolphin Energy Company v. Lazarus Energy Holdings, L.L.C. and Lazarus Louisiana Refinery II, L.L.C., in the 129th District Court of Harris County, Texas (the “Lawsuit”). Blue Dolphin agreed that it will not execute or attempt to execute on an order that was signed on May 16, 2011 in the Lawsuit severing LEH’s counterclaims into Cause No. 2010-32561-A, which resulted in a Partial Summary Judgment becoming a final judgment in Blue Dolphin’s favor. LEH’s claims and causes of action in the Lawsuit were dismissed on July 6, 2012.

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. During the twelve months ended December 31, 2012, a vendor placed a mechanic’s lien on the Nixon Facility as protection during construction activities. Management does not believe that the lien will have a material adverse effect on our results of operations.

Environmental Matters

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

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Notes to Consolidated Financial Statements

(Continued)

(23) 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. Rent expenses for the office lease provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. Rent expense for the office lease was as follows:

Years Ended
December 31,
2012	$	107,609
2011	$	110,313

The following is a schedule of future minimum lease payments under the lease exceeding one year at December 31, 2012:

Years Ending December 31,	Future Minimum Lease Payments
2013		112,206
2014		113,558
2015		113,558
2016		113,558
2017		47,316
	$	500,196

(24) Earnings Per Share

In viewing our earnings per share for the twelve months ended December 31, 2012 and 2011, there are four considerations: (i) the weighted average shares outstanding used to calculate basic and diluted EPS for periods prior to the date of the LE Acquisition was 8,426,456, which takes into account the exchange ratio in the reverse merger between Blue Dolphin and LE, compared to 1 as previously reported, (ii) basic and diluted EPS have been presented on the statements of operations on a continuing and discontinued operations basis due to discontinued operations in 2012 (iii) diluted EPS for the twelve months ended December 31, 2012 excludes stock options outstanding as they would be anti-dilutive and (iv) diluted EPS for the twelve months ended December 31, 2011 excludes stock options as LE had no stock options. See “Note (14) Discontinued Operations” of this report for additional disclosures related to discontinued operations.

For the twelve months ended December 31, 2012, the weighted average number of common shares was computed as LE’s number of common shares outstanding from the beginning of the period to the date of the LE Acquisition combined with Blue Dolphin’s number of common shares outstanding from the date of the LE Acquisition to the end of the period. For all periods prior to the date of the LE Acquisition, the weighted average number of common shares was computed as LE’s one member unit prior to the LE Acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

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(Continued)

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

	Twelve Months Ended December 31,
	2012			2011
Income (loss) from continuing operations, net of tax	$	(13,841,066	)	$	183,854
Loss from discontinued operations, net of tax		(4,443,566	)		-
Net income (loss)		(18,284,632	)		183,854
Basic and diluted earnings (loss) per common share
Continuing operations	$	(1.35	)	$	0.02
Discontinued operations	$	(0.43	)	$	-
Basic and diluted earnings (loss) per common share	$	(1.78	)	$	0.02
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,284,152			8,426,456

(25) Stock Options

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

The Plan provides that upon a change in control, the Compensation Committee may: i) accelerate the vesting of options, cancel options and make payments in respect thereof in cash in accordance with the terms of the Plan, (ii) adjust the outstanding options as appropriate to reflect such change in control or (iii) provide that each option shall thereafter be exercisable for the number and class of securities or property that the optionee would have been entitled to receive had the option been exercised. The Plan provides that a change of control occurs if any person, entity or group acquires or gains ownership or control of more than 50% of the outstanding Common Stock or, if after certain enumerated transactions, the persons who were directors before such transactions cease to constitute a majority of the Board. Issuance of Common Stock to LEH in connection with the LE Acquisition resulted in a change in control under the Plan. The Compensation Committee of the Board approved the continuation of the Plan and determined that each option outstanding under the Plan would remain exercisable for the number and class of securities or property that the optionee was entitled to receive prior to the LE Acquisition. As of the date of the LE Acquisition, all options granted under the Plan had vested.

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Notes to Consolidated Financial Statements

(Continued)

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

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the twelve months ended December 31, 2012. The options outstanding as of December 31, 2011 represent Blue Dolphin (the legal acquirer). LE did not have any options outstanding as of December 31, 2011.

At December 31, 2012, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2011		28,887		$	13.29
Options granted		-		$	-
Options exercised		(8,163	)	$	-
Options expired or cancelled		(6,082	)	$	-
Options outstanding at December 31, 2012		14,642		$	19.67		0.9	$	-
Options exercisable at December 31, 2012		14,642		$	19.67		0.9	$	-

We recognized no compensation expense for vested stock options for the twelve months ended December 31, 2012 and 2011. As of December 31, 2012, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the twelve months ended December 31, 2012, we recognized $84,500 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

(26) Supplemental Oil and Gas Information (Unaudited)

The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

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Blue Dolphin Energy Company & Subsidiaries

Notes to Consolidated Financial Statements

(Continued)

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reported proved reserves and future net cash flows estimates for our U.S. Gulf of Mexico oil and natural gas properties were determined to be uneconomical during 2012.  In addition, on November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Our interests associated with Indonesia were discontinued in 2012. As a result, no reserve reports were prepared as of December 31, 2012.

Estimates of our future net recoverable oil and natural gas as of December 31, 2011 were prepared by independent petroleum engineering consulting firms. Estimated proved net recoverable reserves included only those quantities that were expected to be commercially recoverable. Estimated reserves for the twelve months ended December 31, 2011 were computed using benchmark prices based on the unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas during each month of 2011, as required by SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting,” effective December 31, 2009. Costs were estimated using costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. The reserves reflected for the twelve months ended December 31, 2011 included oil and gas interests in both the North Sumatra Basin offshore Indonesia and U.S. Gulf of Mexico.

Proved reserves are estimated quantities of gas, crude oil, and condensate that geological and engineering data demonstrate, with reasonable certainty, are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.

	Oil			Natural Gas
Quantity of Proved Oil and Gas Reserves	(Bbls)			(Mcf)
Total proved reserves at December 31, 2011		-			-
Reserves acquired		182,574			12,930
Revisions to previous estimates		(182,574	)		(12,930	)
Total proved reserves at December 31, 2012		-			-

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ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified by SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), as appropriate to allow timely decisions regarding required disclosure. Under the supervision of, and with the participation of our management, including our Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on our evaluation, the Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer) have concluded that these controls and procedures were ineffective for the reasons set forth below as of the end of the period covered by this report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Management’s Report on Internal Control over Financial Reporting

Management’s Responsibility. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. A company’s internal control over financial reporting is a process designed 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 in the United States.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Assessment. Management, under the supervision and with the participation of our Chief Executive Officer (principal executive officer) and interim Chief Financial Officer (principal financial officer), assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. In connection with such evaluation, management concluded that our internal control over financial reporting was ineffective as of December 31, 2012 due to certain material weaknesses described below:

●   Inadequate personnel resources to handle complex accounting transactions, which can result in errors related to the recording, disclosure and presentation of consolidated financial information in quarterly, annual and other filings;

●   Lack of formally documented accounting policies and procedures; and

●   Inadequate personnel resources to ensure a complete segregation of duties within the accounting function.

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We intend to take the necessary measures to continue development and implementation of formal policies, improved processes, documented procedures, as well as the continued hiring of additional personnel to better define segregation of duties and improve financial reporting. The actions that we are taking are subject to ongoing senior management review, as well as Audit Committee oversight. Although we plan to complete this remediation process as quickly as possible, we cannot at this time estimate how long it will take, and our initiatives may not prove to be successful in remediating all material weakness.

Changes in Internal Control over Financial Reporting. Other than as described above, there was no change over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15(d)-15(d) of the Exchange Act that occured during the twelve months ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Exemption from Management's Report on Internal Control over Financial Reporting for 2012. This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this annual report.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board Composition

The amended and restated bylaws of Blue Dolphin Energy Company (“Blue Dolphin,” “we,” “us” and “our") provide that the Board of Directors (the “Board”) shall consist of five members, with the precise number to be determined from time to time by the Board, except that no decrease in the number shall have the effect of shortening the term of an incumbent director. The Board currently has five directors, each serving until the next annual meeting of stockholders to be held by the Company.

The following sets forth, as of March 29, 2013, each director’s name, age, principal occupation and directorships during the past five (5) years, as well as their relevant knowledge and experience that led to their appointment to the Board:

Name, Age Principal Occupation and Directorships During Past 5 Years	Knowledge and Experience
Ivar Siem, 66 Blue Dolphin Energy Company Chief Executive Officer (2004 to February 2012) Drillmar Energy, Inc. Chief Executive Officer (since 2005) Mr. Siem has served on Blue Dolphin’s Board since 1989; he is currently Chairman of the Board. He also sits on the Board of Directors of several private companies, including Drillmar Energy, Inc. (a subsidiary of which filed for Chapter 11 reorganization in 2009).	Mr. Siem earned a Bachelor of Science in Mechanical Engineering from the University of California, Berkeley and completed an Executive MBA Program at Dartmouth University. Based on his educational and professional experiences, Mr. Siem possesses particular knowledge and experience in engineering, strategic planning, operations and general management that strengthen the Board’s collective qualifications, skills and experience.
John N. Goodpasture, 64 Copano Energy, L.L.C. Senior Vice President, Corporate Development (since 2010) Texas Eastern Products Pipeline Company, L.L.C. (a general partner of TEPPCO Partners, L.P.) Vice President of Corporate Development (2001 to 2009) Mr. Goodpasture has served on Blue Dolphin’s Board since 2006; he is currently a member of the Audit and Compensation Committees, as well as a member of the Special Committee on MLP Conversion. He previously served on the Board of Directors of the Houston Food Bank.	Mr. Goodpasture earned a Bachelor of Science in Mechanical Engineering from Texas Tech University. Based on his educational and professional experiences, Mr. Goodpasture possesses particular knowledge and experience in the oil and gas industry in business development, capital structure and mergers and acquisitions that strengthen the Board’s collective qualifications, skills and experience.
Christopher T. Morris, 51 MPact Partners President (since 2011) Freddie Mac Vice President (various divisions) (2000 to 2010) Mr. Morris has served on Blue Dolphin’s Board since November 2012; he is currently a member of the Audit and Compensation Committees, as well as Chairman of the Special Committee on MLP Conversion.	Mr. Morris earned a Bachelor of Arts in Economics from Stanford University. He also earned an MBA from Harvard University. Based on his educational and professional experiences, Mr. Morris possesses particular knowledge and experience in business management and strategic planning and business development that strengthen the Board’s collective qualifications, skills and experience.

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Name, Age Principal Occupation and Directorships During Past 5 Years

Knowledge and Experience

A. Haag Sherman, 47 Salient Partners, L.P. Co-founder, Partner and Non-Executive Vice Chairman Salient Partners, L.P. and Affiliates Various Executive Positions, including Chief Investment Officer and Chief Executive Officer (2002 to 2011) Mr. Sherman has served on Blue Dolphin’s Board since February 2012; he is currently Chairman of the Audit Committee and is a member of the Compensation Committee and the Special Committee on MLP Conversion. He also serves on the Board of Directors of PlainsCapital Corporation (a bank holding company with approximately $5 billion in assets), Salient MLP & Infrastructure Fund (NYSE: SMF), the Salient Absolute Return Fund and The Endowment Fund complex.

Mr. Sherman graduated cum laude with a Bachelor of Business Administration in Accounting from Baylor University and earned his Juris Doctorate with honors from the University of Texas School of Law. He is an attorney and certified public accountant, in both cases licensed in the State of Texas. Mr. Sherman possesses extensive knowledge in accounting, finance, investment management and corporate law, as well as a keen understanding of the regulatory and corporate governance requirements of publicly traded companies, which strengthens the Board’s collective qualifications, skills and experience.

Herbert N. Whitney, 72   Wildcat Consulting, LLC Founder and President (since 2006)   Mr. Whitney has served on Blue Dolphin’s Board since February 2012. He previously served on the Board of Directors of Blackwater Midstream Corporation, the Advisory Board of Sheetz, Inc., as Chairman of the Board of Directors of Colonial Pipeline Company and as Chairman of the Executive Committee of the Association of Oil Pipelines.     Mr. Whitney has more than forty-three (43) years of experience in pipeline operations, crude oil supply, product supply, distribution and trading, as well as marine operations and logistics having served as the President of CITGO Pipeline Company and in various general manager positions at CITGO Petroleum Corporation. He earned his Bachelor of Science in Civil Engineering from Kansas State University. Based on his educational and professional experiences, he possesses extensive knowledge in the supply and distribution of crude oil and petroleum products, which strengthens the Board’s collective qualifications, skills and expertise.

Family Relationships between Directors and Officers

As of March 29, 2013, there were no family relationships between any of our directors or executive officers.

Post-Acquisition Executive Officers

The following sets forth, as of March 29, 2013, the name and age of each executive officer, as well as their principal occupation during the past five (5) years:

Name	Position	Since	Age
Jonathan P. Carroll	Chief Executive Officer, President, Assistant Treasurer and Secretary	2012	51
Tommy L. Byrd	Interim Chief Financial Officer, Treasurer and Assistant Secretary	2012	55

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Jonathan P. Carroll was appointed Chief Executive Officer, President, Assistant Treasurer and Secretary of Blue Dolphin in February 2012. He has also been a member of LEH since 2006, and has served as a Principal at Carroll and Company Capital Management since 1988. LEH owns eighty percent (80%) of our issued and outstanding Common Stock. Mr. Carroll serves on the Board of Managers of LEH, as well as a trustee to the Salient MLP & Infrastructure Fund (NYSE:SMF), the Salient Absolute Return Fund and The Endowment Fund. Mr. Carroll earned a Bachelor of Arts in Human Biology and a Bachelor of Arts in Economics from Stanford University.

Tommy L. Byrd was appointed Interim Chief Financial Officer, Treasurer and Assistant Secretary of Blue Dolphin in February 2012 having previously served as our Controller since November 2011. He is also an employee of LEH, where he has served since 2006. Mr. Byrd has extensive financial management, accounting and internal audit experience in the energy industry. Prior to joining LEH, he served as Chief Financial Officer of Baard Energy LLC from 2004 to 2006. From 2000 to 2004, he was Project Audit Manager at TXU Energy. From 1987 to 1998, Mr. Byrd held various positions, including Controller, at MG Trade Finance Corp. He earned a Bachelor of Business Administration in Accounting from Stephen F. Austin State University.

Committees and Meetings of the Board

Board. Following our acquisition of Lazarus Energy, LLC (“LE”) in February 2012 (the “LE Acquisition”), the Board consisted of Dr. Laurence N. Benz and Messrs. Goodpasture, Sherman, Siem and Whitney with Mr. Siem serving as Chairman. Dr. Benz resigned from the Board in November 2012, at which time Christopher T. Morris was appointed to the Board. The Board held three (3) regular meetings and four (4) special meetings. Each director attended at least 75% of the total number of meetings of the Board and committees on which he served. The Board has two standing committees, the Audit Committee and the Compensation Committee. In November 2012, the Board established a Special Committee of the Board to oversee a potential conversion of Blue Dolphin from a Delaware “C” corporation to a Delaware master limited partnership.

Audit Committee. Following the LE Acquisition, the Audit Committee consisted of Dr. Benz and Messrs. Goodpasture and Sherman with Mr. Sherman serving as Chairman. Dr. Benz resigned from the Audit Committee in November 2012, at which time Christopher T. Morris was appointed to the Audit Committee. The Audit Committee met five (5) times. The Board has affirmatively determined that all members of the Audit Committee are independent and that Messrs. Morris and Sherman qualify as Audit Committee Financial Experts. The Audit Committee's duties include overseeing financial reporting and internal control functions and the Audit Committee’s charter is available on our website (www.blue-dolphin-energy.com).

Compensation Committee. Following the LE Acquisition, the Compensation Committee consisted of Dr. Benz and Messrs. Goodpasture and Sherman with Mr. Sherman serving as Chairman. Dr. Benz resigned from the Compensation Committee in November 2012, at which time Christopher T. Morris was appointed to the Compensation Committee. The Compensation Committee did not meet during the fiscal year ended December 31, 2012. The Board has affirmatively determined that all members of the Compensation Committee are independent. The Compensation Committee does not have a charter, however, its duties are to oversee and set our compensation policies, to approve compensation of our executive officers and to administer our stock incentive plan.

Nominating Committee. Given the size of the Board and that a majority of its members are independent, as defined under National Association of Securities Dealers Automated Quotations (“NASDAQ”) Listing Rules, the Board adopted a “Board Nomination Procedures” policy in July 2005 in lieu of appointing a standing nominating committee. The policy is used by independent members of the Board when choosing nominees to stand for election.

The Board will consider for possible nomination qualified nominees recommended by stockholders. As addressed in the “Board Nomination Procedures” policy, the manner in which independent directors evaluate nominees for director as recommended by a stockholder will be the same as that for nominees received from other sources.

The Board will continue to nominate qualified directors of whom the Board believes will make important contributions to the Board and the Company. The Board generally requires that nominees be persons of sound ethical character, be able to represent all stockholders fairly, have demonstrated professional achievements, have meaningful experience and have a general appreciation of the major business issues facing us.The Board also considers issues of diversity and background in its selection process, recognizing that it is desirable for its membership to have differences in viewpoints, professional experiences, educational backgrounds, skills, race, gender, age and national origin.

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Corporate Governance

Leadership Structure. Our leadership structure is designed to ensure consistent and effective leadership through open communication between the Board and management. As part of this structure, Ivar Siem serves as Chairman of the Board and Jonathan P. Carroll serves as Chief Executive Officer and President. Messrs. Siem and Carroll work in concert with the independent directors to oversee the execution of our strategy. This arrangement has proven effective for us following the LE Acquisition and the Board believes it will continue to best serve the interests of Blue Dolphin and its stockholders.

Risk Oversight. Our Board is actively involved in overseeing Blue Dolphin’s risk management. Presentations by management to the Board include consideration of the challenges and risks to our business, and the Board and management actively engage in discussion on these topics. Furthermore, the two standing Board committees provide appropriate risk oversight. The Audit Committee oversees the accounting and financial reporting processes, as well as compliance, internal control, legal and risk matters. The Compensation Committee oversees compensation policies, including the approval of compensation for the Board and its committees, as well as management members. We believe that the processes established to report and monitor systems for material risks applicable to us are appropriate and effective.

Code of Conduct. In July 2005, the Board adopted a code of conduct (the “Code of Conduct”) applicable to all directors, officers and employees, as set forth in the Sarbanes-Oxley Act of 2002, which is publicly available on our website (www.blue-dolphin-energy.com). The Code of Conduct requires all directors, officers and employees to act ethically at all times, and prohibits any employee from retaliating or taking any adverse action against anyone for raising or helping to resolve an integrity concern.

The Audit Committee established procedures to enable anyone who has a concern about our conduct or policies, or any employee who has a concern about our accounting, internal accounting controls or auditing matters, to communicate that concern directly to the Chairman of the Audit Committee. Violations and/or concerns may be sent anonymously by email to A. Haag Sherman at haagsherman@gmail.com or such other contact information for Mr. Sherman that we may post on our website from time to time.

Code of Ethics. In April 2003, the Board adopted a Code of Ethics policy that is applicable to the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. The Code of Ethics policy is posted on our website (www.blue-dolphin-energy.com) and is available to any stockholder, without charge, upon written request to Blue Dolphin Energy Company, Attention: Secretary, 801 Travis Street, Suite 2100, Houston, Texas 77002. Any amendments or waivers to provisions of the Code of Ethics policy will be disclosed on our website.

Communicating with Directors. As the Board does not receive a large volume of correspondence from stockholders, at this time, there is no formal process by which stockholders can communicate with the Board. Instead, any stockholder who desires to contact the Board or specific members of the Board may do so by writing to: Blue Dolphin Energy Company, Attention: Secretary for the Board, 801 Travis Street, Suite 2100, Houston, Texas 77002. Currently, all communications addressed in such manner are sent directly to the indicated directors. In the future, if the Board adopts a formal process for determining how communications are to be relayed to directors, that process will be disclosed on our website.

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ITEM 11.  EXECUTIVE COMPENSATION

Executive Compensation Policy and Procedures

Pursuant to a Management Agreement between Blue Dolphin, LE and Lazarus Energy Holdings, LLC (“LEH”) dated February 15, 2012 (the “Management Agreement”), all Blue Dolphin subsidiaries are managed by LEH and all personnel work directly for LEH. LEH is reimbursed for providing personnel services under the Management Agreement.

We do not offer a retirement plan that provides for the payment of retirement benefits. In the event an employee retires after age 65, the non-vested portion of any stock options received expires immediately. The vested portion of any stock options received expires, to the extent not exercised, three months after retirement.

Our stock incentive plan provides that upon a change of control, the Compensation Committee may accelerate the vesting of options, cancel options and make payments in respect thereof in cash in accordance with the terms of the stock incentive plan, adjust the outstanding options as appropriate to reflect such change of control or provide that each option shall thereafter be exercisable for the number and class of securities or property that the optionee would have been entitled to receive had the option been exercised. The stock incentive plan provides that a change of control occurs if any person, entity or group acquires or gains ownership or control of more than 50% of the outstanding common stock, par value $0.01 per share, (“Common Stock”) or, if after certain enumerated transactions, the persons who were directors before such transactions cease to constitute a majority of the Board. Issuance of Common Stock to LEH in connection with the LE Acquisition resulted in a change in control under the stock incentive plan. The Compensation Committee of the Board approved the continuation of the stock incentive plan and determined that each option outstanding under the current stock incentive plan would remain exercisable for the number and class of securities or property that the optionee was entitled to receive prior to the LE Acquisition. As of the date of the LE Acquisition, all options granted under our existing plan had vested.

Compensation for Named Executives

Pursuant to the Management Agreement all Blue Dolphin subsidiaries are managed by LEH and all personnel work directly for LEH. LEH is reimbursed for proving personnel services under the Management Agreement. The compensation paid to our principal executive officer and the most highly compensated executive officer other than the principal executive officer whose annual salary exceeded $100,000 in the fiscal year ended December 31, 2012 for services rendered to Blue Dolphin was paid by LEH. Therefore the summary compensation table has been excluded.

Compensation Risk Assessment

LEH’s approach to compensation practices and policies applicable for non-executive employees throughout our organization is consistent with that followed for executive employees. Base pay is based on market median for each position, and bonuses and stock based incentives are based on individual and Blue Dolphin’s performance. LEH believes its practices and policies in this regard are not reasonably likely to have a materials adverse effect on us.

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Outstanding Equity Awards at Fiscal Year End

	Option Awards
Name	Number of Securities Underlying Unexercised Options - Exercisable		Number of Securities Underlying Unexercised Options - Unexercisable		Option Exercise Price		Option Expiration Date
Ivar Siem		14,285		-	$	19.67	10/15/2013

Director Compensation Policy and Procedures

We do not have any directors that are also our employees. Compensation for members of the Board and committees of the Board is approved by the Board based on recommendations by Mr. Siem as Chairman of the Board.

Compensation for Non-Employee Directors

During 2012, non-employee directors were paid an annual retainer of $20,000, payable quarterly in Common Stock with the number of shares based upon the fair value on the date of payment. Issued shares were restricted from sale pursuant to holding periods under Rule 144 of the Securities Act, and applicable state securities laws. During 2012, the Audit Committee chairman received an additional annual retainer of $5,000 and other Audit Committee members received an additional annual retainer of $2,500. The Audit Committee retainer was payable semi-annually in cash. No additional compensation was paid to directors serving on the Compensation Committee. Directors were entitled to reimbursement for reasonable out-of-pocket expenses related to in-person meeting attendance.

The following table sets forth the compensation paid to non-employee directors during 2012:

Name	Fees Earned or Paid in Cash		Stock Awards(1)		Total
Laurence N. Benz(2)	$	1,250	$	24,500	$	25,750
John N. Goodpasture	$	1,250	$	25,000	$	26,250
Christopher T. Morris(3)	$	-	$	5,000	$	5,000
A. Haag Sherman	$	2,500	$	15,000	$	17,500
Herbert W. Whitney	$	-	$	15,000	$	15,000

(1)   At December 31, 2012, each non-employee director had total stock awards outstanding as follows: Dr. Benz – 37,311, Mr. Goodpasture – 30,107, Mr. Morris – 1,299, Mr. Sherman – 2,723 and Mr. Whitney – 2,723.

(2)   Dr. Benz resigned from the Board effective November 6, 2012.

(3)   Mr. Morris was appointed to the Board effective November 7, 2012.

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ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

The table below sets forth information with respect to persons or groups known to us to be the beneficial owners of more than five percent (5%) of our Common Stock as of March 29, 2013.Unless otherwise indicated, each named party has sole voting and positive power with respect to such shares.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class(1)
Common Stock	Lazarus Energy Holdings, LLC		8,426,456		79.7	%

(1)   Based upon 10,577,939 shares outstanding (10,563,297 shares of Common Stock issued and outstanding and 14,642 shares of Common Stock issuable upon exercise of stock options, both as of March 29, 2013).

Security Ownership of Management

The table below sets forth information as of March 29, 2013 with respect to: (i) directors and nominees, (ii) executive officers and (iii) directors and executive officers as a group beneficially owning our Common Stock. Unless otherwise indicated, each of the following persons has sole voting and dispositive power with respect to such shares.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class(1)
Common Stock	Jonathan P. Carroll(2)		8,426,598		79.7	%
Common Stock	Ivar Siem		104,466		1.0	%
Common Stock	John N. Goodpasture		30,107		*
Common Stock	A. Haag Sherman		2,723		*
Common Stock	Herbert N. Whitney		2,723		*
Common Stock	Christopher T. Morris		1,299		*
Common Stock	Tommy L. Byrd		---		---
Directors/Nominees and Executive Officers as a Group (7 Persons)			8,567,916		81.0	%

(1)   Based upon 10,577,939 shares outstanding (10,563,297 shares of Common Stock issued and outstanding and 14,642 shares of Common Stock issuable upon exercise of stock options, both as of March 29, 2013).

(2)   Includes 8,426,456 shares issued to LEH. Mr. Carroll is Director / Manager of LEH.

   * Less than 1%.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers and stockholders who own more than ten percent (10%) of our Common Stock to file reports of stock ownership and changes in ownership with the SEC and to furnish us with copies of all such reports as filed. Based solely on a review of the copies of the Section 16(a) reports furnished to us, we are aware that during 2012, no filings were made late.

Equity Compensation Plan Information

The following table provides information for all equity compensation plans as of the twelve months ended December 31, 2012, under which our equity securities were authorized for issuance:

	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Plan Category	(a)		(b)		(c)
Equity compensation plans approved by
security holders		14,642	$	19.67		915,149
Equity compensation plans not approved
by security holders		-		-		-
Total		14,642	$	19.67		915,149

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Party Transactions

LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock.  Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, and Tommy L. Byrd, our interim Chief Financial Officer, Treasurer and Assistant Secretary, are also a member and employee, respectively, of LEH and, as a result may, under certain circumstances, have interests that differ from or conflict with our interests.  Herbert N. Whitney, a member of our Board, currently serves as a consultant to LEH.  In connection with our acquisition of LE, we entered into the Management Agreement pursuant to which LEH manages and operates the Nixon Facility and Blue Dolphin’s other operations.  As a result of their relationship with LEH, Messrs. Carroll and Byrd may experience conflicts of interest in the execution of their duties on behalf of Blue Dolphin including with respect to the Management Agreement.

Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 bpd processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We also agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month.  Aggregate amounts expensed for Services by LEH at the Nixon Facility for the twelve months ended December 31, 2012 were $8,603,155 (approximately $2.71 per barrel).  At December 31, 2012 and 2011, the amounts owed to LEH were $1,594,021 and $908,139, respectively.

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 year-to-year renewals at the option of either party thereafter, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by the Board and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

Director Independence

The Board has affirmatively determined that each of its members, with the exception of Mr. Whitney is independent and has no material relationship with us (either directly or indirectly or as a stockholder or officer of an organization that has a relationship with us), and that all members of the Audit and Compensation Committees are independent, pursuant to NASDAQ Listing and SEC rules. Mr. Whitney serves as a consultant to LEH.

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ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees paid to UHY by us in the twelve months ended December 31, 2012 and 2011 were as follows:

	2012		2011
Audit fees	$	285,246	$	134,101
Audit-related fees		7,054		-
Tax fees		6,437		16,485
All other fees		-		5,750
Total	$	298,737	$	156,336

Audit fees for 2012 and 2011 included fees related to the audit of our consolidated financial statements and review of our quarterly reports that are filed with the Securities and Exchange Commission. Tax fees for 2012 and 2011 primarily include fees for preparation of federal and state income tax returns as well as tax planning services. The Audit Committee must pre-approve all audit and non-audit services provided to us by our independent registered public accounting firm.

Remainder of Page Intentionally Left Blank

93

PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) List of documents filed as part of this report

3.  Exhibits. We hereby file as part of this Annual Report on Form 10-K the Exhibits listed in the attached Exhibit Index.

No.  Description 

3.1  Amended and Restated Certificate of Incorporation of Blue Dolphin. (1)

3.2  Amended and Restated By-Laws of Blue Dolphin. (2)

4.1  Specimen Stock Certificate.(3)

4.2  Form of Promissory Note issued pursuant to the Note and Warrant PurchaseAgreement dated September 8, 2004. (4)

4.3 Promissory Note of Lazarus Louisiana Refinery II, LLC, payable to Blue Dolphin dated July 31, 2009. (5)

10.1  Blue Dolphin 2000 Stock Incentive Plan.(6) *

10.2  First Amendment to the Blue Dolphin 2000 Stock Incentive Plan.(7) *

10.3 Second Amendment to the Blue Dolphin 2000 Stock Incentive Plan. (8) *

10.4 Fourth Amendment to the Blue Dolphin 2000 Stock Incentive Plan. (9) *

10.5 Purchase and Sale Agreement by and between Blue Dolphin Pipe Line Company and MCNIC, dated February 1, 2002.(10)

10.6 Sale of American Resources Offshore, Inc. Common Stock Agreement between Blue Dolphin Exploration Co. and Ivar Siem, dated September 8, 2004. (4)

10.7 Purchase and Sale Agreement by and between Blue Dolphin, WBI Pipeline & Storage Group, Inc. and SemGas LP, dated October 29, 2004. (11)

10.8 Amendment to the Asset Purchase Agreement by and among MCNIC Offshore Pipeline and Processing Company and Blue Dolphin Pipe Line Company dated February 28, 2005. (12)

10.9 Placement Agency Agreement by and between Blue Dolphin and Starlight Investments, LLC dated May 27, 2005. (13)

10.10 Form of Stock Purchase Agreement between Blue Dolphin and Osler Holdings Limited, Gilbo Invest AS, Spencer Energy AS, Spencer Finance Corp., Hudson Bay Fund, LP, Don Fogel and SIBEX Capital Fund, Inc. dated March 8, 2006. (14)

10.11 Loan and Option Agreement by and among Lazarus Energy Holdings, LLC, Lazarus Louisiana Refinery II, LLC, Lazarus Energy, LLC, Lazarus Environmental, LLC, and Blue Dolphin dated July 31, 2009. (15)

94

10.12 Sale and Purchase Agreement by and among Blue Dolphin Exploration Company, Blue Sky Langsa Limited and Blue Sky Energy and Power Inc. dated July 21, 2010. (16)

10.13 Option Agreement by and among Blue Dolphin Exploration Company, Blue Sky Langsa Limited and Blue Sky Energy and Power Inc. dated July 21, 2010. (17)

10.14 Purchase and Sale Agreement dated July 12, 2011 by and among Blue Dolphin, Lazarus  Energy Holdings, LLC, Lazarus Louisiana Refinery II, LLC, Lazarus Texas Refinery II, LLC, Lazarus Environmental, LLC, Lazarus Energy, LLC and Lazarus Energy Development, LLC. (18)

10.15 Asset Purchase Agreement by and among Sunoco Partners Marketing & Terminals L.P. and Blue Dolphin Pipe Line Company and Bitter Creek Pipelines, LLC dated August 3, 2011.**

10.16 Management Agreement by and between Lazarus Energy Holdings, LLC, Lazarus Energy, LLC and Blue Dolphin effective as of February 15, 2012. (19)

10.17 Loan Agreement dated September 29, 2008 among 1st International Bank as Lender, Lazarus Energy LLC as Borrower and Jonathan Pitts Carroll, Sr. and Lazarus Energy Holdings LLC as Guarantors. (20)

10.18 Subordination Agreement effective August 21, 2008 by Notre Dame Investors, Inc. in favor of First International Bank. (21)

10.19 Intercreditor and Subordination Agreement dated September 29, 2008 by and between Notre Dame Investors, Inc., Richard Oberlin, Lazarus Energy LLC and First International Bank. (22)

10.20 Letter Agreement dated September 12, 2011 between GEL Tex Marketing, LLC, Milam Services, Inc., 1st International Bank, Lazarus Energy LLC and Lazarus Energy Holdings LLC. (23)

10.21 Forbearance Agreement dated August 12, 2011 by and among 1st International Bank, Lazarus Energy LLC, Jonathan P. Carroll, Gina L. Carroll, Lazarus Energy Holdings, LLC, GEL Tex Marketing, LLC and Milam Services, Inc. (24)

10.22 Promissory Note between Lazarus Energy LLC as maker and Notre Dame Investors Inc. as Payee in the Principal Amount of $8,000,000 dated June 1, 2006. (25)

10.23 Intercreditor and Subordination Agreement dated August 12, 2011 by and among John H. Kissick, Lazarus Energy LLC and Milam Services, Inc. (26)

10.24 Crude Oil Supply and Throughput Services Agreement by and between GEL Tex Marketing, LLC and Lazarus Energy, LLC dated as of August 12, 2011. (27)

10.25 Construction and Funding Contract by and between Lazarus Energy, LLC dated as of August 12, 2011. (28)

10.26 Joint Marketing Agreement by and between GEL Tex Marketing, LLC and Lazarus Energy, LLC dated as of August 12, 2011. (29)

10.27 Acknowledgment Letter between Lazarus Energy, LLC and GEL Tex Marketing, LLC dated June 1, 2012. (30)

10.28 Letter Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC dated June 25, 2012. (31)

10.29 Letter Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC dated July 30, 2012. (32)

10.30 Letter Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC dated August 1, 2012. (33)

10.31 Letter Agreement dated June 10, 2012 between Lazarus Energy Holdings, LLC and Blue Dolphin Energy Company. (34)

10.32 Sale and Purchase Agreement by and among Blue Dolphin Exploration Company and Blue Sky Langsa Limited dated November 6, 2012. (35)

95

10.33 Escrow Agreement by and among Blue Dolphin Exploration Company, Blue Sky Langsa Limited and Doherty & Doherty, LLC dated November 6, 2012. (36)

10.34 Assignment Agreement by and among Blue Dolphin Exploration Company and Blue Sky Langsa Limited dated November 6, 2012.(37)

10.35 Letter Agreement dated December 20, 2012 between Lazarus Energy, LLC, GEL Tex Marketing, LLC and Milam Services, Inc. **

14.1 Code of Ethics applicable to the Chairman, Chief Executive Officer and SeniorFinancial Officer. (38)

21.1 List of Subsidiaries of Blue Dolphin.**

23.1 Consent of UHY LLP.**

23.2 Consent of American Energy Advisors, Inc.(39)

23.3 Consent of Lonquist & Co., LLC.(40)

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 adoptedpursuant 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 adoptedpursuant 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 adoptedpursuant to section 906 of the Sarbanes-Oxley Act of 2002. **

99.1 Report of American Energy Advisors, Inc., Petroleum Engineer Consultant.(41)

99.2  Report of Lonquist & Co. LLC, Petroleum Engineer Consultant.(42)

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. **

_______________

*    Management Compensation Plan.

**  Filed herewith

96

(1)   Incorporated herein by reference to Exhibit 3.1 filed in connection with the Form 8-K of Blue Dolphin under the Exchange Act dated June 2, 2009 (Commission File No. 000-15905).

(2)   Incorporated herein by reference to Exhibit 3.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated December 26, 2007 (Commission File No. 000-15905).

(3)   Incorporated herein by reference to exhibits filed in connection with Form 10-K of Blue Dolphin for the twelve months ended December 31, 1989 under the Exchange Act dated March 30, 1990 (Commission File No. 000-15905).

(4)   Incorporated herein by reference to Exhibit 10.4 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated September 14, 2004 (Commission File No. 000-15905).

(5)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated August 6, 2009 (Commission File No. 000-15905).

(6)   Incorporated herein by reference to Appendix 1 filed in connection with the Proxy Statement of Blue Dolphin under the Exchange Act dated April 20, 2000 (Commission File No. 000-15905).

(7)   Incorporated herein by reference to Appendix B filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated April 16, 2003 (Commission File No. 000-15905).

(8)   Incorporated herein by reference to Appendix A filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated April 27, 2006 (Commission File No. 000-15905).

(9)   Incorporated herein by reference to Exhibit B filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated December 28, 2011 (Commission File No. 000-15905).

(10)   Incorporated herein by reference to Exhibit 10.20 filed in connection with Form 10-KSB of Blue Dolphin under the Exchange Act dated March 21, 2003 (Commission File No. 000-15905).

(11)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated November 3, 2004 (Commission File No. 000-15905).

(12)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated March 3, 2005 (Commission File No. 000-15905).

(13)   Incorporated herein by reference to Exhibit 10.9 filed in connection with Form 10-KSB of Blue Dolphin for the twelve months ended December 31, 2005 under the Exchange Act dated March 30, 2006 (Commission File No. 000-15905).

(14)   Incorporated herein by reference to Exhibit 10.10 filed in connection with Form 10-KSB of Blue Dolphin for the twelve months ended December 31, 2005 under the Exchange Act dated March 30, 2006 (Commission File No. 000-15905).

(15)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated August 6, 2009 (Commission File No. 000-15905).

(16)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 21, 2010 (Commission File No. 000-15905).

(17)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 21, 2010 (Commission File No. 000-15905).

(18)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 22, 2011 (Commission File No. 000-15905).

97

(19)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Amendment No. 1 to Form 8-K of Blue Dolphin under the Exchange Act dated March 14, 2012 (Commission File No. 000-15905).

(20)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(21)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(22)   Incorporated herein by reference to Exhibit 10.3 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(23)   Incorporated herein by reference to Exhibit 10.4 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(24)   Incorporated herein by reference to Exhibit 10.5 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(25)   Incorporated herein by reference to Exhibit 10.6 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(26)   Incorporated herein by reference to Exhibit 10.7 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(27)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(28)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(29)   Incorporated herein by reference to Exhibit 10.3 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(30)   Incorporated herein by reference to Exhibit 10.4 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(31)   Incorporated herein by reference to Exhibit 10.5 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(32)   Incorporated herein by reference to Exhibit 10.6 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(33)   Incorporated herein by reference to Exhibit 10.7 filed in connection with Form 10-Q of Blue Dolphin under the Exchange Act dated June 30, 2012 (Commission File No. 000-15905).

(34)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated June 14, 2012 (Commission File No. 000-15905).

(35)   Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated November 13, 2012 (Commission File No. 000-15905).

(36)   Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated November 13, 2012 (Commission File No. 000-15905).

(37)   Incorporated herein by reference to Exhibit 10.3 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated November 13, 2012 (Commission File No. 000-15905).

98

(38)   Incorporated herein by reference to Exhibit 14.1 filed in connection with Form 10-KSB of Blue Dolphin for the twelve months ended December 31, 2004 31, 2004 under the Exchange Act dated March 25, 2005 (Commission File No. 000-15905).

(39)   Incorporated herein by reference to Exhibit 23.2 filed in connection with Form 10-K of Blue Dolphin for the twelve months ended December 31, 2011 under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(40)   Incorporated herein by reference to Exhibit 23.3 filed in connection with Form 10-K of Blue Dolphin for the twelve months ended December 31, 2011 under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(41)   Incorporated herein by reference to Exhibit 99.1 filed in connection with Form 10-K of Blue Dolphin for the twelve months ended December 31, 2011 under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

(42)   Incorporated herein by reference to Exhibit 99.2 filed in connection with Form 10-K of Blue Dolphin for the twelve months ended December 31, 2011 under the Exchange Act dated March 31, 2012 (Commission File No. 000-15905).

Remainder of Page Intentionally Left Blank

99

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: April 1, 2013	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chief Executive Officer, President Assistant Treasurer and Secretary (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JONATHAN P. CARROLL	Chief Executive Officer, President,	April 1, 2013
Jonathan P. Carroll	Assistant Treasurer and Secretary
	(Principal Executive Officer)
/s/ TOMMY L. BYRD	Interim Chief Financial Officer,	April 1, 2013
Tommy L. Byrd	Treasurer and Assistant Secretary
	(Principal Financial Officer)
/s/ IVAR SIEM	Chairman of the Board	April 1, 2013
Ivar Siem
/s/ CHRISTOPHER T. MORRIS	Director	April 1, 2013
Christopher T. Morris
/s/ JOHN N. GOODPASTURE	Director	April 1, 2013
John N. Goodpasture
/s/ A. HAAG SHERMAN	Director	April 1, 2013
A. Haag Sherman
/s/ HERBERT N. WHITNEY	Director	April 1, 2013
Herbert N. Whitney

 100

EX-10.35

Exhibit 10.35

genesisenergy

December 20, 2012

Lazarus Energy LLC

801 Travis, Suite 2100

Houston, Texas 77002

Attention: Jonathan Carroll

GEL TEX Marketing, LLC Milam Services, Inc.

919 Milam, Suite 2100

Houston, Texas 77002

Attention: Steve Nathanson

Re: Letter Agreement Regarding December Distributions

Gentlemen:

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

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

Section 1. Acknowledgements

The parties agree that for the month of December 2012, GEL has made and will make weekly Operations Payments and other payments to or on behalf of Lazarus (such payments, the "December Payments Amount") which in the aggregate will exceed the amount that should have been paid under the JMA. The amount by which the December Payments Amount exceeds the amount required to be paid to Lazarus in the month of December 2012, pursuant to the JMA is hereinafter referred to as the "Overpayment Amount".

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

1

December 20, 2012 Page 2

Section 2. Modifications to Distributions and Payments Provisions of JMA

From and after January 1, 2013, any Gross Profit distributions that would have been paid to Lazarus under the terms of Exhibit B, subsection (c)(iii) of the JMA, shall be distributed instead to GEL (the "Redirected Distributions") until GEL has received aggregate Redirected Distributions equal to the Overpayment Amount. Such distributions shall not reduce the distributions of Gross Profit that GEL or its Affiliates are otherwise entitled to under the JMA.

Section 3, Certain Representations

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

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

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

Signature Page Follows

2

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

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

3

EX-21.1

Exhibit 21.1

List of subsidiaries of Blue Dolphin Energy Company (“Blue Dolphin”):

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

●   Lazarus Refining & Marketing, LLC (“LRM”), a Delaware limited liability company

●   Blue Dolphin Pipe Line Company, a Delaware corporation;

●   Blue Dolphin Petroleum Company, a Delaware corporation;

●   Blue Dolphin Services Co., a Texas corporation;

●   Blue Dolphin Exploration Company, a Delaware corporation; and

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

Blue Dolphin acquired one hundred percent (100%) of the issued and outstanding membership interests of LE effective February 15, 2012 and LRM effective October 1, 2012.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-134156, 333-38606 and 333-124908) of Blue Dolphin Energy Company of our report dated April 1, 2013, relating to our audit of the consolidated financial statements, which appear in this Annual Report on Form 10-K for the year ended December 31, 2012.

/s/ UHY LLP

UHY LLP

Sterling Heights, Michigan

April 1, 2013

EX-31.1

Exhibit 31.1

I, Jonathan P. Carroll, certify that:

1. I have reviewed this annual report on Form 10-K of Blue Dolphin Energy Company (the “Registrant”).

2. Based on my knowledge, this annual 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 periods covered by this annual report;

3. Based on my knowledge, the financial statements and other financial information included in this annual 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 annual 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 annual 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 annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

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

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:

(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: April 1, 2013

/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 annual report on Form 10-K of Blue Dolphin Energy Company (the “Registrant”).

2. Based on my knowledge, this annual 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 periods covered by this annual report;

3. Based on my knowledge, the financial statements and other financial information included in this annual 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 annual 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 annual 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 annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

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

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:

(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: April 1, 2013

/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 OF

PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Blue Dolphin Energy Company (the “Blue Dolphin”) on Form 10-K for the period ended December 31, 2012 (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 Blue Dolphin, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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 Blue Dolphin.

/s/ JONATHAN P. CARROLL

Jonathan P. Carroll

Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)

April 1, 2013

EX-32.2

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Blue Dolphin Energy Company (the “Blue Dolphin”) on Form 10-K for the period ended December 31, 2012 (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 (Principal Financial Officer) of Blue Dolphin, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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 Blue Dolphin.

/s/ TOMMY L. BYRD

Tommy L. Byrd

Interim Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

April 1, 2013

XML

9. Concentration of Risk (Tables)

12 Months Ended

Dec. 31, 2012

Concentration Of Risk Tables

Petroleum products sales to total sales

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

	December 31,			December 31,
	2012			2011
Low-sulfur diesel		48.7	%		-
Naphtha		26.2	%		-
Atmospheric gas oil		25.1	%		-
		100.0	%		-

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4. LE Acquisition (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Feb. 14, 2012 As Reported	Feb. 14, 2012 Adjustments	Feb. 14, 2012 Revised Purchase Price Allocation
Current assets			$ 2,466,901		$ 2,466,901
Oil and gas properties			1,503,596	3,639,279	5,142,875
Pipelines			4,466,273	4,757,563	9,223,836
Onshore separation and handling facilities			325,435		325,435
Land			473,225		473,225
Other property and equipment			282,972		282,972
Other long term assets			9,463		9,463
Trade name			184,368	118,978	303,346
Goodwill			8,667,401	(7,221,681)	1,445,720
Total assets acquired			18,379,634	1,294,139	19,673,773
Current liabilities			333,480		333,480
Asset retirement obligations	921,260			1,294,139	1,294,139
Total liabilities assumed			333,480	1,294,139	1,627,619
Net assets acquired			$ 18,046,154		$ 18,046,154

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21. Income Tax (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Tables

Changes in deferred tax assets and deferred tax liabilities

Deferred tax assets (liabilities):
Net operating loss and capital loss carryforwards	$	8,482,237
Start-up costs (Nixon Refinery)		1,922,708
Basis differences in property and equipment		(1,044,223	)
Other		312,826
Total deferred tax assets		9,673,548
Less: valuation allowance		(9,673,548	)
Deferred tax assets, net	$	-

Effective Tax Rate

Expected tax rate	34.00	%
Permanent differences	(0.17	%)
State tax	(0.04	%)
Change in valuation allowance	(33.84	%)
	(0.05	%)

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14. Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Revenue	$ 352,094,714
Depletion, depreciation and amortization	1,622,864	17,684
Loss from discontinued operations, net of tax	(4,443,566)
Indonesia
Revenue	674,797
Lease operating expenses	788,525
Depletion, depreciation and amortization	124,811
Impairment expense	3,858,427
Bad debt expense	321,732
Accretion expense	24,868
Total costs and expenses	5,118,363
Loss from discontinued operations, net of tax	$ (4,443,566)

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4. LE Acquisition (Details1) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
REVENUE FROM OPERATIONS
Total revenue from operations	$ 429,480
COST OF OPERATIONS
Abandonment expense	1,184,549
Impairment of oil and gas properties	9,435,745
Bad debt expense	9,508
OTHER INCOME (EXPENSE)
Loss from discontinued operations, net of tax	(4,443,566)
Net loss	13,078,963
Historical Blue Dolphin
REVENUE FROM OPERATIONS
Refined product sales
Pipeline operations	446,236	931,500
Oil and gas sales	28,957	1,342,718
Total revenue from operations	475,193	2,274,218
COST OF OPERATIONS
Cost of refined products sold
Refinery operating expenses
Pipeline operating expenses	450,634	1,008,859
Lease operating expenses	66,122	1,174,252
Abandonment expense	1,184,549
Depletion, depreciation and amortization	571,164	591,927
Impairment of oil and gas properties	9,435,745
Bad debt expense	9,508
General and administrative expenses	1,954,196	1,574,364
Accretion expense	115,812	131,690
Total cost of operations	13,787,730	4,733,798
Gain on sale of property and equipment		3,081,053
Loss from operations	(13,312,537)	621,473
OTHER INCOME (EXPENSE)
Net tank rental revenue
Interest and other income	9,720	17,383
Interest expense	(2,529)
Total other income (expense)	7,191	17,383
Loss before income taxes	(13,305,346)	638,856
Income tax expense	(9,678)	(20,921)
Loss from continuing operations, net of tax	(13,315,024)
Loss from discontinued operations, net of tax	(4,445,433)
Net loss	(17,760,457)	617,935
Historical LE
REVENUE FROM OPERATIONS
Refined product sales	351,665,234
Pipeline operations
Oil and gas sales
Total revenue from operations	351,665,234
COST OF OPERATIONS
Cost of refined products sold	342,035,755
Refinery operating expenses	8,603,155
Pipeline operating expenses
Lease operating expenses
Abandonment expense
Depletion, depreciation and amortization	1,082,124	17,684
Impairment of oil and gas properties
Bad debt expense
General and administrative expenses	295,694	645,444
Accretion expense
Total cost of operations	352,022,393	663,128
Gain on sale of property and equipment	5,665
Loss from operations	(357,159)	(663,128)
OTHER INCOME (EXPENSE)
Net tank rental revenue	534,047	874,421
Interest and other income	13,059	23,901
Interest expense	(952,050)	(51,340)
Total other income (expense)	(404,944)	846,982
Loss before income taxes	(762,103)	183,854
Income tax expense
Loss from continuing operations, net of tax	(762,103)
Loss from discontinued operations, net of tax
Net loss	(762,103)	183,854
Pro Forma Consolidated
REVENUE FROM OPERATIONS
Refined product sales	351,665,234
Pipeline operations	446,236	931,500
Oil and gas sales	28,957	1,342,718
Total revenue from operations	352,140,427	2,274,218
COST OF OPERATIONS
Cost of refined products sold	342,035,755
Refinery operating expenses	8,603,155
Pipeline operating expenses	450,634	1,008,859
Lease operating expenses	66,122	1,174,252
Abandonment expense	1,184,549
Depletion, depreciation and amortization	1,653,288	609,611
Impairment of oil and gas properties	9,435,745
Bad debt expense	9,508
General and administrative expenses	2,249,890	2,219,808
Accretion expense	115,812	131,690
Total cost of operations	365,810,123	5,396,926
Gain on sale of property and equipment	5,665	3,081,053
Loss from operations	(13,669,696)	(41,655)
OTHER INCOME (EXPENSE)
Net tank rental revenue	534,047	874,421
Interest and other income	22,779	41,284
Interest expense	(954,579)	(51,340)
Total other income (expense)	(397,753)	864,365
Loss before income taxes	(14,067,449)	822,710
Income tax expense	(9,678)	(20,921)
Loss from continuing operations, net of tax	(14,077,127)
Loss from discontinued operations, net of tax	(4,445,433)
Net loss	$ (18,522,560)	$ 801,789

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20. Long-Term Debt (Details 1) (USD $)	Dec. 31, 2012
Long-Term Debt Details 1
2013	$ 1,861,256
2014	1,972,878
2015	2,092,528
2016	718,292
2017	411,203
Subsequent to 2017	8,750,320
long Term Debt Payment, Net	$ 15,806,477

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18. Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Oil and Gas Properties and Pipelines and Facilities Assets

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

	December 31,			December 31,
	2012			2011
Fair value of asset retirement obligations at February 15, 2012	$	1,294,139		$	-
Liabilities incurred		-			-
Liabilities extinguished		(361,680	)		-
Liabilities settled		(141,099	)		-
Accretion expense from continuing operations		105,032			-
Accretion from discontinued operations		24,868			-
Asset retirement obligations as of December 31, 2012		921,260			-
Less: current portion of asset retirement obligations		-			-
Asset retirement obligations, long-term balance
at December 31, 2012	$	921,260		$	-

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26. Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Dec. 31, 2012

Extractive Industries [Abstract]

Supplemental Oil and Gas Information (Unaudited)

Supplemental Oil and Gas Information (Unaudited)

The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reported proved reserves and future net cash flows estimates for our U.S. Gulf of Mexico oil and natural gas properties were determined to be uneconomical during 2012.  In addition, on November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Our interests associated with Indonesia were discontinued in 2012. As a result, no reserve reports were prepared as of December 31, 2012.

Estimates of our future net recoverable oil and natural gas as of December 31, 2011 were prepared by independent petroleum engineering consulting firms. Estimated proved net recoverable reserves included only those quantities that were expected to be commercially recoverable. Estimated reserves for the twelve months ended December 31, 2011 were computed using benchmark prices based on the unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas during each month of 2011, as required by SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting,” effective December 31, 2009. Costs were estimated using costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. The reserves reflected for the twelve months ended December 31, 2011 included oil and gas interests in both the North Sumatra Basin offshore Indonesia and U.S. Gulf of Mexico.

Proved reserves are estimated quantities of gas, crude oil, and condensate that geological and engineering data demonstrate, with reasonable certainty, are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.

	Oil			Natural Gas
Quantity of Proved Oil and Gas Reserves	(Bbls)			(Mcf)
Total proved reserves at December 31, 2011		-			-
Reserves acquired		182,574			12,930
Revisions to previous estimates		(182,574	)		(12,930	)
Total proved reserves at December 31, 2012		-			-

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20. Long-Term Debt (Details 2) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Cost	$ 9,396	$ 9,396
Less: Accumulated amortization	4,541	3,602
Equipment held under capital leases	$ 4,855	$ 5,794

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17. Accrued Expenses and Other Current Liabilities (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Accrued Expenses And Other Current Liabilities Details
Storage lease		$ 480,000
Excise taxes	292,303
Salaries	134,501	184,909
Transportation	69,551
Property taxes		37,171
Insurance		21,770
Unrealized hedging loss	136,100
Unearned revenue	92,783	21,071
Accrued Expenses and Other Current Liabilities, Net	$ 725,238	$ 744,921

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25. Stock Options (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Shares
Options outstanding at December 31, 2011	28,887
Options granted
Options exercised	(8,163)
Options expired or cancelled	(6,082)
Options outstanding at December 31, 2012	14,642
Options exercisable at December 31, 2012	14,642
Weighted Average Exercise Price
Options outstanding at December 31, 2011	$ 13.29
Options granted
Options exercised
Options expired or cancelled
Options outstanding at December 31, 2012	$ 19.67
Options exercisable at December 31, 2012	$ 19.67
Weighted Average Remaining Contractual Life
Options outstanding at December 31, 2012	10 months 24 days
Options exercisable at December 31, 2012	10 months 24 days
Aggregate Intrinisic Value
Options outstanding at December 31, 2012
Options exercisable at December 31, 2012

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5. Lazarus Refining & Marketing, LLC (LRM) Acquisition (Details Narrative) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Assets	$ 56,381,926	$ 38,144,056
Liabilities	39,761,086	22,481,970
Lazarus Refining & Marketing, LLC
Assets	100,285
Liabilities	$ 499,591

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19. Impairment (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Impairment Details Narrative
Impairment	$ 9,435,745

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23. Leases (Details 1) (USD $)	Dec. 31, 2012
Leases Details 1
2013	$ 112,206
2014	113,558
2015	113,558
2016	113,558
2017	47,316
Leases Futurre Minimum Payment, Net	$ 500,196

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21. Income Taxes (Details) (USD $)	Dec. 31, 2012
Income Taxes Details
Net operating loss and capital loss carryforwards	$ 8,482,237
Start-up costs (Nixon Facility)	1,922,708
Basis differences in property and equipment	(1,044,223)
Other	312,826
Total deferred tax assets	9,673,548
Less: valuation allowance	(9,673,548)
Deferred tax assets, net

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24. Earnings per share (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]
Income (loss) from continuing operations, net of tax	$ (13,841,066)	$ 183,854
Loss from discontinued operations, net of tax	(4,443,566)
Net income (loss)	$ (18,284,632)	$ 183,854
Continuing operations	$ (1.35)	$ 0.02
Discontinued operations	$ (0.43)
Basic and diluted earnings (loss) per common share	$ (1.78)	$ 0.02
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,284,152	8,426,456

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20. Long-Term Debt (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Refinery Loan	$ 9,298,183	$ 9,669,173
Notre Dame Debt	1,300,000	1,300,000
Construction and Funding Agreement	5,206,175	3,319,193
Captial Leases	2,119	6,237
Total	15,806,477	14,294,603
Less: Current portion of long-term debt	1,816,960	1,839,501
Long term debt	$ 13,989,517	$ 12,455,102

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15. Accounts Payable, Related Party (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Payables and Accruals [Abstract]
Services provided by LEH	$ 1,594,021	$ 908,139
Expense for service	$ 8,603,155

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18. Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(18) Asset Retirement Obligations

Refinery and Facilities

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

Oil and Gas Properties and Pipelines and Facilities Assets

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

	December 31,			December 31,
	2012			2011
Fair value of asset retirement obligations at February 15, 2012	$	1,294,139		$	-
Liabilities extinguished		(361,680	)		-
Liabilities settled		(141,099	)		-
Accretion expense from continuing operations		105,032			-
Accretion from discontinued operations		24,868			-
Asset retirement obligations as of December 31, 2012		921,260			-
Less: current portion of asset retirement obligations		-			-
Asset retirement obligations, long-term balance
at December 31, 2012	$	921,260		$	-

During the twelve months ended December 31, 2012, plugging and abandonment costs related to our High Island A-7 oil and gas property exceeded the amount reserved for the ARO liability. Accordingly, the excess amount, which was $1,184,549, was recognized as a loss during the period. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

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24. Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Earnings per share

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

	Twelve Months Ended December 31,
	2012			2011
Income (loss) from continuing operations, net of tax	$	(13,841,066	)	$	183,854
Loss from discontinued operations, net of tax		(4,443,566	)		-
Net income (loss)		(18,284,632	)		183,854
Basic and diluted earnings (loss) per common share
Continuing operations	$	(1.35	)	$	0.02
Discontinued operations	$	(0.43	)	$	-
Basic and diluted earnings (loss) per common share	$	(1.78	)	$	0.02
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,284,152			8,426,456

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12. Inventories (Tables)

12 Months Ended

Dec. 31, 2012

Inventory Disclosure [Abstract]

Inventories

Inventory balances consisted of the following:

	December 31,		December 31,
	2012		2011
Low-sulfur diesel	$	397,240	$	2,193,864
Naphtha		1,562,055		1,067,011
Atmospheric gas oil		322,356		1,010,877
Other liquids		-		64,486
Propane		-		59,599
Crude		19,041		134,289
Supplies		-		3,835
	$	2,300,692	$	4,533,961

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18. Asset Retirement Obligations (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012
Asset Retirement Obligations Details Narrative
Loss on exceeded the amount reserved for the ARO liability	$ 1,184,549

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7. Fair Value Measurement (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at December 31, 2012 and 2011 due to their short-term maturities. The fair value of our longer term debt for the twelve months ended December 31, 2012 and 2011 was $15,806,477 and $14,294,603, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and the basis for that measurement:

			Fair Value Measurement at December 31, 2012 Using
Financial assets:	Carrying Value as at December 31, 2012		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	$	136,100	$	136,100	$	-	$	-

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26. Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Oil And Gas Information Tables

Quantity of Proved Oil and Gas Reserves

	Oil			Natural Gas
Quantity of Proved Oil and Gas Reserves	(Bbls)			(Mcf)
Total proved reserves at December 31, 2011		-			-
Reserves acquired		182,574			12,930
Revisions to previous estimates		(182,574	)		(12,930	)
Total proved reserves at December 31, 2012		-			-

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11. Deposits (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Deposits Details
Utility deposits	$ 36,500	$ 36,500
Equipment deposits	124,526	124,526
Tax bonds	792,000	312,000
Purchase option deposits	283,421
Deposits	$ 1,236,447	$ 473,026

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7. Fair Value Measurement (Details Narrative) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Fair Value Measurement Details Narrative
Fair value of longer term debt	$ 15,806,477	$ 14,294,603

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20. Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long Term Debt

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

	December 31,		December 31,
	2012		2011
Refinery Loan	$	9,298,183	$	9,669,173
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		5,206,175		3,319,193
Captial Leases		2,119		6,237
		15,806,477		14,294,603
Less: Current portion of long-term debt		1,816,960		1,839,501
	$	13,989,517	$	12,455,102

Future Long Term Debt payment

The following is a schedule of future long-term debt payments:

Years Ending December 31,	Amount
2013	$	1,861,256
2014		1,972,878
2015		2,092,528
2016		718,292
2017		411,203
Subsequent to 2017		8,750,320
	$	15,806,477

Equipment Under Capital Lease

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

	December 31,		December 31,
	2012		2011
Cost	$	9,396	$	9,396
Less: Accumulated amortization		4,541		3,602
	$	4,855	$	5,794

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2. Basis of Presentation

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Basis of Presentation

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

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details) (Refined products - net short (long) positions)	Dec. 31, 2012
Refined products - net short (long) positions
2012	30,000
2013
2014
2015

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

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	December 31,		December 31,
	2012		2011
Refinery and facilities	$	34,000,199	$	-
Pipelines and facilities		1,233,811		-
Onshore separation and handling facilities		325,435		-
Land		577,965		104,740
Other property and equipment		577,567		217,136
		36,714,977		321,876
Less: Accumulated depletion, depreciation and amortization		1,674,151		62,443
		35,040,826		259,433
Construction in Progress		821,259		32,048,496
Property, Plant and Equipment, Net	$	35,862,085	$	32,307,929

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22. Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(22) Commitments and Contingencies

Management Agreement

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

Genesis Agreements

We are highly dependent on our relationship with Genesis and its affiliates. Our relationship with Genesis is governed by three agreements:

● Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. After the expiration of its initial term, the Crude Supply Agreement automatically renews for successive one year terms unless either party notifies the other party of its election to terminate the Crude Supply Agreement within 90 days of the expiration of the then current term.

● Construction and Funding Agreement -- Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam has continued to make advances in excess of their obligation, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.   The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement for a breach or upon termination of the Refinery Loan Forbearance Agreement. If Milam terminates the Construction and Funding Agreement, then: (i) Milam and LE are required to execute a forbearance agreement, the form of which has been previously agreed to, pursuant to which LE will pay Milam a fee of $150,000 per month in order to maintain the forbearance (such amount shall be credited against the amount owed) for a period of six months (during which time Milam will agree not to foreclose pursuant to the Construction and Funding Agreement and, thus, LE has the right to find financing to pay off such amounts), (ii) Milam shall be entitled to receive payment in full for all obligations owed under the Construction and Funding Agreement, (iii) all liens in favor of Milam will remain in full force and effect until released in accordance with the terms of the Construction and Funding Agreement and (iv) upon repayment of all obligations owed to Milam pursuant to the terms of the forbearance agreement executed by Milam and LE, LE shall have no further obligations to Milam or its affiliates under the Construction and Funding Agreement;

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

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

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

(c)

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

(d)

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

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

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. After the expiration of its initial term, the Joint Marketing Agreement shall be automatically renewed for successive one year terms unless either party notifies the other party of its election to terminate the Joint Marketing Agreement within 90 days of the expiration of the then current term. The Joint Marketing Agreement also provides that it may be terminated prior to the end of its then current term under certain circumstances.

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

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

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

As of December 31, 2012, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,206,175. As of December 31, 2012, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $659,883.

As of December 31, 2012, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the twelve months ended December 31, 2012, payments made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits were approximately $287,091.

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

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

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

Lazarus Energy Development, LLC (“LED”) Option

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

Legal Matters

Pursuant to a Settlement Agreement and Mutual Release dated February 15, 2012 (the “Settlement Agreement”), by and among Blue Dolphin, LEH and Lazarus Louisiana Refinery II, LLC (“LLRII”), the parties agreed to settle and compromise all disputes between them in connection with closing of the LE Acquisition. LEH agreed to file a non-suit with prejudice of all pending claims against Blue Dolphin under Cause No. 210-32561, styled Blue Dolphin Energy Company v. Lazarus Energy Holdings, L.L.C. and Lazarus Louisiana Refinery II, L.L.C., in the 129th District Court of Harris County, Texas (the “Lawsuit”). Blue Dolphin agreed that it will not execute or attempt to execute on an order that was signed on May 16, 2011 in the Lawsuit severing LEH’s counterclaims into Cause No. 2010-32561-A, which resulted in a Partial Summary Judgment becoming a final judgment in Blue Dolphin’s favor. LEH’s claims and causes of action in the Lawsuit were dismissed on July 6, 2012.

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. During the twelve months ended December 31, 2012, a vendor placed a mechanic’s lien on the Nixon Facility as protection during construction activities. Management does not believe that the lien will have a material adverse effect on our results of operations.

Environmental Matters

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

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21. Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

(21) Income Taxes

LE is a limited liability company and, prior to the LE Acquisition, its taxable income or loss flowed through to its sole member for federal and state income tax purposes. Blue Dolphin is a “C” corporation and is a taxable entity for federal and state income tax purposes. Upon LE's Acquisition, LE became the legal subsidiary of Blue Dolphin and LE’s taxable income or loss flows through to Blue Dolphin for federal and state income tax purposes. As a result of the LE Acquisition, Section 382 of the Internal Revenue Code imposes a limitation on the use Blue Dolphin’s NOLs. At December 31, 2012, we did not recognize any deferred tax assets resulting from our NOLs due to the uncertainty of their use.

Income tax expense was $9,678 for the twelve months ended December 31, 2012. Income tax expense related to state income tax.

The income tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2012 is presented below:

Deferred tax assets (liabilities):
Net operating loss and capital loss carryforwards	$	8,482,237
Start-up costs (Nixon Refinery)		1,922,708
Basis differences in property and equipment		(1,044,223	)
Other		312,826
Total deferred tax assets		9,673,548
Less: valuation allowance		(9,673,548	)
Deferred tax assets, net	$	-

In assessing the recoverability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. A full valuation allowance against our net deferred tax asset was recorded at December 31, 2012 due to our uncertainty as to the utilization of the deferred tax assets in the foreseeable future.

Our effective tax rate applicable to continuing operations in 2012 was as follows:

Expected tax rate	34.00	%
Permanent differences	(0.17	%)
State tax	(0.04	%)
Change in valuation allowance	(33.84	%)
	(0.05	%)

As a result of the LE Acquisition, Section 382 of the Internal Revenue code imposes potential limitations on the use of our net operating loss (“NOL”) carryovers. The amount of NOL subject to such limitations is approximately $18.5 million. The NOL generated subsequent to the LE Acquisition, approximately $6.4 million, is not subject to any such limitation. For the twelve months ended December 31, 2012, we did not recognize any deferred tax asset related to such NOL’s due to the uncertainty of its use.

We have adopted the provisions of the ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. 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. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The provisions of the guidance on accounting for uncertainty in income taxes have been applied to all of our material tax positions taken for all open tax years on the date of adoption through the fiscal year ended December 31, 2012. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the guidance.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the year ended December 31, 2012. Furthermore, none of our federal and state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. As of December 31, 2012, fiscal years 2009 and later remain subject to examination by the IRS and fiscal years 2008 and later remain subject to examination by State of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.

The State of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin revenue to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross profit revenue rather than on its net income, certain aspects of TMT make it similar to an income tax. At December 31, 2012, we accrued $0 in TMT.

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4. LE Acquisition (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012
Business Combinations [Abstract]
Revenue	$ 429,480
Net loss	$ 13,078,963

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14. Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Discontinued Operations Tables

Discontinued operations

On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012. The operating results of the discontinued operations are summarized as follows:

	December 31,			December 31,
	2012			2011
Revenue	$	674,797		$	-
Lease operating expenses		788,525			-
Depletion, depreciation and amortization		124,811			-
Impairment expense		3,858,427			-
Bad debt expense		321,732			-
Accretion expense		24,868			-
Total costs and expenses		5,118,363			-
Loss from discontinued operations, net of tax	$	(4,443,566	)	$	-

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23. Leases

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Leases

We are currently under a ten-year lease agreement that expires in 2017 for office space in downtown Houston, Texas. The Houston office serves as our company headquarters. Rent expenses for the office lease provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. Rent expense for the office lease was as follows:

Years Ended
December 31,
2012	$	107,609
2011	$	110,313

The following is a schedule of future minimum lease payments under the lease exceeding one year at December 31, 2012:

Years Ending December 31,	Future Minimum Lease Payments
2013		112,206
2014		113,558
2015		113,558
2016		113,558
2017		47,316
	$	500,196

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24. Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

In viewing our earnings per share for the twelve months ended December 31, 2012 and 2011, there are four considerations: (i) the weighted average shares outstanding used to calculate basic and diluted EPS for periods prior to the date of the LE Acquisition was 8,426,456, which takes into account the exchange ratio in the reverse merger between Blue Dolphin and LE, compared to 1 as previously reported, (ii) basic and diluted EPS have been presented on the statements of operations on a continuing and discontinued operations basis due to discontinued operations in 2012 (iii) diluted EPS for the twelve months ended December 31, 2012 excludes stock options outstanding as they would be anti-dilutive and (iv) diluted EPS for the twelve months ended December 31, 2011 excludes stock options as LE had no stock options. See “Note (14) Discontinued Operations” of this report for additional disclosures related to discontinued operations.

For the twelve months ended December 31, 2012, the weighted average number of common shares was computed as LE’s number of common shares outstanding from the beginning of the period to the date of the LE Acquisition combined with Blue Dolphin’s number of common shares outstanding from the date of the LE Acquisition to the end of the period. For all periods prior to the date of the LE Acquisition, the weighted average number of common shares was computed as LE’s one member unit prior to the LE Acquisition multiplied by the exchange ratio of 8,426,456 shares for the one member unit.

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

	Twelve Months Ended December 31,
	2012			2011
Income (loss) from continuing operations, net of tax	$	(13,841,066	)	$	183,854
Loss from discontinued operations, net of tax		(4,443,566	)		-
Net income (loss)		(18,284,632	)		183,854
Basic and diluted earnings (loss) per common share
Continuing operations	$	(1.35	)	$	0.02
Discontinued operations	$	(0.43	)	$	-
Basic and diluted earnings (loss) per common share	$	(1.78	)	$	0.02
Basic and Diluted
Weighted average number of shares of common stock
outstanding and potential dilutive shares of common stock		10,284,152			8,426,456

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1. Organization

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Company Operations

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

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

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

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

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

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

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

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

Effective February 15, 2012, Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE from Lazarus Energy Holdings, LLC (“LEH”), a Delaware limited liability company (the “LE Acquisition”). The LE Acquisition was accounted for as a reverse merger using accounting principles applicable to reverse acquisitions whereby the financial statements subsequent to the date of the transaction are presented as a continuation of LE (the legal subsidiary). See “Note (4) LE Acquisition” of this report for further information related to the LE Acquisition.

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25. Stock Options

12 Months Ended

Dec. 31, 2012

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

Stock Options

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

The Plan provides that upon a change in control, the Compensation Committee may: i) accelerate the vesting of options, cancel options and make payments in respect thereof in cash in accordance with the terms of the Plan, (ii) adjust the outstanding options as appropriate to reflect such change in control or (iii) provide that each option shall thereafter be exercisable for the number and class of securities or property that the optionee would have been entitled to receive had the option been exercised. The Plan provides that a change of control occurs if any person, entity or group acquires or gains ownership or control of more than 50% of the outstanding Common Stock or, if after certain enumerated transactions, the persons who were directors before such transactions cease to constitute a majority of the Board. Issuance of Common Stock to LEH in connection with the LE Acquisition resulted in a change in control under the Plan. The Compensation Committee of the Board approved the continuation of the Plan and determined that each option outstanding under the Plan would remain exercisable for the number and class of securities or property that the optionee was entitled to receive prior to the LE Acquisition. As of the date of the LE Acquisition, all options granted under the Plan had vested.

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

Pursuant to FASB ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the twelve months ended December 31, 2012. The options outstanding as of December 31, 2011 represent Blue Dolphin (the legal acquirer). LE did not have any options outstanding as of December 31, 2011.

At December 31, 2012, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2011		28,887		$	13.29
Options granted		-		$	-
Options exercised		(8,163	)	$	-
Options expired or cancelled		(6,082	)	$	-
Options outstanding at December 31, 2012		14,642		$	19.67		0.9	$	-
Options exercisable at December 31, 2012		14,642		$	19.67		0.9	$	-

We recognized no compensation expense for vested stock options for the twelve months ended December 31, 2012 and 2011. As of December 31, 2012, there was no unrecognized compensation cost related to non-vested stock options granted under the Plan.

For the twelve months ended December 31, 2012, we recognized $84,500 of expense related to the fair value issuance of restricted common stock to our independent directors as compensation for services rendered.

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21. Income Taxes (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Income Taxes Details Narrative
Income tax expense	$ 9,678
Accrued Texas margins tax	$ 0

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10. Prepaid Expenses and Other Current Assets (Tables)

12 Months Ended

Dec. 31, 2012

Prepaid Expenses And Other Current Assets Tables

Prepaid balances

Prepaid balances consisted of the following:

	December 31,		December 31,
	2012		2011
Prepaid insurance	$	185,814	$	27,100
Employee advances		22,500		25,083
Property insurance		-		3,741
Workers compensation insurance		-		2,789
Prepaid loan closing fees		20,000		-
	$	228,314	$	58,713

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3. Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Restricted cash	$ 89,593	$ 192,004
Uninsured balances	170,896	0
Perecentage of revenue from major customers	84.00%
Four major customers Accounts Recievable	11,400,000
Accumulated amortization	143,645	109,847
Amortization expense	25,349	25,349
Debt issuance costs	675,980	675,980
Interest expense	$ 8,450	$ 8,450

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16. Note Payable (Details Narrative) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Short-term note	$ 43,941	$ 46,318
Unsecured note balance	39,866	46,318
Unsecured short term note balance	$ 4,075

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Dec. 31, 2012	Dec. 31, 2011
ASSETS
Cash and cash equivalents	$ 420,896	$ 1,822
Restricted cash	89,593	192,004
Accounts receivable, net	15,398,755
Prepaid expenses and other current assets	228,314	58,713
Deposits	1,236,447	473,026
Inventory	2,300,692	4,533,961
Total current assets	19,674,697	5,259,526
Property, plant and equipment, net	35,862,085	32,307,929
Debt issue costs, net	532,335	566,133
Other assets	9,463	10,468
Trade name	303,346
TOTAL ASSETS	56,381,926	38,144,056
CURRENT LIABILITIES
Accounts payable	19,171,013	4,841,859
Accounts payable, related party	1,594,021	908,139
Note payable	43,941	46,318
Accrued expenses and other current liabilities	725,238	744,921
Interest payable, current portion	640,352	995,916
Long-term debt, current portion	1,816,960	1,839,501
Total current liabilities	23,991,525	9,376,654
Long-term liabilities:
Asset retirement obligations	921,260
Long term debt, net of current portion	13,989,517	12,455,102
Long term interest payable, net of current portion	858,784	650,214
Total long-term liabilities	15,769,561	13,105,316
TOTAL LIABILITIES	39,761,086	22,481,970
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized, 10,563,297 and 8,426,456 shares issued and outstanding at December 31, 2012 and December 31, 2011, respectively)	105,633	84,265
Additional paid-in capital	36,524,142	17,302,124
Accumulated deficit	(20,008,935)	(1,724,303)
Total stockholders' equity	16,620,840	15,662,086
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 56,381,926	$ 38,144,056

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17. Accrued Expenses and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Accrued Expenses And Other Current Liabilities Tables

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,		December 31,
	2012		2011
Storage lease	$	-	$	480,000
Excise taxes		292,303		-
Salaries		134,501		184,909
Transportation		69,551		-
Property taxes		-		37,171
Insurance		-		21,770
Unrealized hedging loss		136,100
Unearned revenue		92,783		21,071
	$	725,238	$	744,921

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES
Net income (loss)	$ (18,284,632)	$ 183,854
Loss from discontinued operations	4,443,566
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,611,708	17,684
Impairment expense	9,435,745
Unrealized loss on derivatives	136,100
Amortization of debt issue costs	33,799	33,799
Amortization of intangible assets	10,468	(10,468)
Accretion expense	105,032
Abandonment expense	503,454
Common stock issued for services	163,499
Bad debt expense	9,508
Changes in operating assets and liabilities (net of effects of Acquisition in 2012)
Restricted cash	102,411	33,797
Accounts receivable	(14,724,996)
Prepaid expenses and other current assets	43,894	(58,712)
Deposits	(763,421)	(397,407)
Inventory	2,288,436	(4,484,521)
Accounts payable, accrued expenses and other liabilities	12,160,088	4,950,484
Accounts payable, related party	3,228,128	(16,227)
Net cash provided by operating activities - continuing operations	502,787	252,283
Net cash used in operating activities - discontinued operations	(435,460)
Net cash provided by operating activities	67,327	252,283
INVESTING ACTIVITIES
Capital expenditures	(2,852,460)	(3,507,850)
Cash acquired on Acquisition	1,674,709
Net cash used in investing activities	(1,177,751)	(3,507,850)
FINANCING ACTIVITIES
Proceeds from issuance of debt	4,788,623	3,304,300
Payments on long term debt	(3,276,748)	(42,610)
Proceeds from notes payable	24,548
Payments on notes payable	(26,925)	(5,034)
Proceeds from excercse of stock options	20,000
Net cash provided by financing activities	1,529,498	3,256,656
Net increase in cash and cash equivalents	419,074	1,089
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,822	733
CASH AND CASH EQUIVALENTS AT END OF PERIOD	420,896	1,822
Non-cash investing and financing activities:
Related party payable converted to equity	993,732
Issuance of stock for acquisition of Blue Dolphin at fair value, inclusive of cash acquired of $1,674,709	18,046,154
Accrued services payable converted to common stock	$ 183,500

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6. Business Segment Information (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012
Segment Reporting [Abstract]
Cost of refined products sold realized loss	$ 90,507
Cost of refined products sold unrealized gain	$ 136,100

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4. LE Acquisition (Tables)

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Provisional price allocation for net assets acquired

The below table summarizes the purchase price allocation of the net assets acquired and measurement period adjustments as of the acquisition date (as adjusted). The estimated fair values of the assets acquired and liabilities assumed were based on information that was available as of the acquisition date. Measurement period adjustments for Blue Dolphin were completed during 2012.

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

Supplemental Pro Forma Information

The following pro forma condensed consolidated statements of operations for the twelve months ended December 31, 2012 and 2011 consolidate the historical consolidated statements of operations of Blue Dolphin and LE giving effect to the LE Acquisition as if it had occurred on January 1, 2011. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only:

	Twelve Months Ended December 31, 2012
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$	-		$	351,665,234		$	351,665,234
Pipeline operations		446,236			-			446,236
Oil and gas sales		28,957			-			28,957
Total revenue from operations		475,193			351,665,234			352,140,427
COST OF OPERATIONS
Cost of refined products sold		-			342,035,755			342,035,755
Refinery operating expenses		-			8,603,155			8,603,155
Pipeline operating expenses		450,634			-			450,634
Lease operating expenses		66,122			-			66,122
Abandonment expense		1,184,549			-			1,184,549
Depletion, depreciation and amortization		571,164			1,082,124			1,653,288
Impairment of oil and gas properties		9,435,745			-			9,435,745
Bad debt expense		9,508			-			9,508
General and administrative expenses		1,954,196			295,694			2,249,890
Accretion expense		115,812			-			115,812
Gain on sale of property and equipment		-			5,665			5,665
Total cost of operations		13,787,730			352,022,393			365,810,123
Loss from operations		(13,312,537	)		(357,159	)		(13,669,696	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			534,047			534,047
Interest and other income		9,720			13,059			22,779
Interest expense		(2,529	)		(952,050	)		(954,579	)
Total other income (expense)		7,191			(404,944	)		(397,753	)
Loss before income taxes		(13,305,346	)		(762,103	)		(14,067,449	)
Income tax expense		(9,678	)		-			(9,678	)
Loss from continuing operations, net of tax		(13,315,024	)		(762,103	)		(14,077,127	)
Loss from discontinued operations, net of tax		(4,445,433	)		-			(4,445,433	)
Net loss	$	(17,760,457	)	$	(762,103	)	$	(18,522,560	)

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

	Twelve Months Ended December 31, 2011
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Pipeline operations	$	931,500		$	-		$	931,500
Oil and gas sales		1,342,718			-			1,342,718
Total revenue from operations		2,274,218			-			2,274,218
COST OF OPERATIONS
Pipeline operating expenses		1,008,859			-			1,008,859
Lease operating expenses		1,174,252			-			1,174,252
Depletion, depreciation and amortization		591,927			17,684			609,611
General and administrative expenses		1,574,364			645,444			2,219,808
Accretion expense		131,690			-			131,690
Total cost of operations		4,733,798			663,128			5,396,926
Gain on sale of property and equipment		3,081,053			-			3,081,053
Income (loss) from operations		621,473			(663,128	)		(41,655	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			874,421			874,421
Interest and other income		17,383			23,901			41,284
Interest expense		-			(51,340	)		(51,340	)
Total other income		17,383			846,982			864,365
Income before income taxes		638,856			183,854			822,710
Income tax expense		(20,921	)		-			(20,921	)
Net income	$	617,935		$	183,854		$	801,789

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

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9. Concentration of Risk (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk	100.00%	0.00%
Low-sulfur diesel
Concentration Risk	48.70%	0.00%
Naphtha
Concentration Risk	26.20%	0.00%
Atmospheric gas oil
Concentration Risk	25.10%	0.00%

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15. Accounts Payable, Related Party

12 Months Ended

Dec. 31, 2012

Payables and Accruals [Abstract]

Accounts Payable, Related Party

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

Under the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 barrels per day processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We further agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month. The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and GELTex Marketing, LLC (“GEL”) dated August 12, 2011(the “Joint Marketing Agreement”), which has an initial term of three years and year-to-year renewals at the option of either party thereafter, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by our Board of Directors (the “Board”) and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.

Aggregate amounts expensed for Services at the Nixon Facility for the twelve months ended December 31, 2012 were $8,603,155 (approximately $2.71 per barrel). At December 31, 2012 and 2011, the amounts outstanding to LEH were $1,594,021 and $908,139, respectively, and are reflected in accounts payable, related party in the condensed consolidated balance sheets. LE related party payable was converted to LE’s members’ equity in the amount of $993,732 on the effective date of the LE Acquisition.

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

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6. Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Business segment reporting

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

Twelve Months Ended December 31, 2012
	Segment
						Oil and Gas
	Refinery		Pipeline			Exploration &			Corporate &
	Operations		Transportation			Production			Other(1)			Total
Revenue	$	351,665,234	$	406,812		$	22,668		$	-		$	352,094,714
Operation cost(2)	$	350,940,269	$	8,676,242		$	2,018,126		$	2,270,009			363,904,646
Other non-interest income	$	534,047		-			-			-			534,047
EBITDA	$	1,259,012	$	(8,269,430	)	$	(1,995,458	)	$	(2,270,009	)
Depletion, depreciation and
amortization													(1,622,864	)
Other income (expense), net													(932,639	)
Loss from continuing operations,
before income taxes												$	(13,831,388	)
Loss from discontinued operations												$	(4,443,566	)
Capital expenditures	$	2,852,460	$	-		$	-		$	-		$	2,852,460
Identifiable assets(3)	$	52,745,767	$	1,861,055		$	48,247		$	1,726,854		$	56,381,926

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of the economic hedges on our refined petroleum products, executed by Genesis, is included within operation cost of our Crude Oil and Condensate Processing group. Cost of refined products sold includes a realized loss of $90,507 and an unrealized gain of $136,100 for the twelve months ended December, 2012.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the twelve months ended December 31, 2011 (and at December 31, 2011) were as follows:

	Twelve Months Ended December 31, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenue	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		645,444		-		-		-		645,444
Other non-interest income		874,421		-		-		-		874,421
EBITDA	$	228,977	$	-	$	-	$	-
Depletion, depreciation and
amortization										(17,684	)
Other income (expense), net										(27,439	)
Income from continuing operations
before income taxes									$	183,854
Capital expenditures	$	3,507,850	$	-	$	-	$	-	$	3,507,850
Identifiable assets(3)	$	38,144,056	$	-	$	-	$	-	$	38,144,056

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

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17. Accrued Expenses and Other Current Liabilities

12 Months Ended

Dec. 31, 2012

Payables and Accruals [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,		December 31,
	2012		2011
Storage lease	$	-	$	480,000
Excise taxes		292,303		-
Salaries		134,501		184,909
Transportation		69,551		-
Property taxes		-		37,171
Insurance		-		21,770
Unrealized hedging loss		136,100
Unearned revenue		92,783		21,071
	$	725,238	$	744,921

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12. Inventories (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Inventory Disclosure [Abstract]
Low-sulfur diesel	$ 397,240	$ 2,193,864
Naphtha	1,562,055	1,067,011
Atmospheric gas oil	322,356	1,010,877
Other liquids		64,486
Propane		59,599
Crude	19,041	134,289
Supplies		3,835
Inventory	$ 2,300,692	$ 4,533,961

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Condensed Consolidated Statements of Cash Flows (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Statement of Cash Flows [Abstract]
Cash acquired from business acquisition	$ 1,674,709	$ 1,674,709

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,563,297	8,426,456
Common stock, shares outstanding	10,563,297	8,426,456

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10. Prepaid Expenses and Other Current Assets

12 Months Ended

Dec. 31, 2012

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

10. Prepaid Expenses and Other Current Assets

Prepaid balances consisted of the following:

	December 31,		December 31,
	2012		2011
Prepaid insurance	$	185,814	$	27,100
Employee advances		22,500		25,083
Property insurance		-		3,741
Workers compensation insurance		-		2,789
Prepaid loan closing fees		20,000		-
	$	228,314	$	58,713

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26. Supplemental Oil and Gas Information (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2012
Oil
Total proved reserves at December 31, 2011	-
Reserves acquired	182,574
Revisions to previous estimates	(182,574)
Total proved reserves at December 31, 2012	-
Natural Gas
Total proved reserves at December 31, 2011	-
Reserves acquired	12,930
Revisions to previous estimates	(12,930)
Total proved reserves at December 31, 2012	-

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Mar. 29, 2013	Jun. 30, 2012
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 14,361,145
Entity Common Stock, Shares Outstanding		10,563,297
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012

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11. Deposits

12 Months Ended

Dec. 31, 2012

Cash and Cash Equivalents [Abstract]

11. Deposits

Deposit balances consisted of the following:

	December 31,		December 31,
	2012		2011
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		312,000
Purchase option deposits		283,421		-
Deposits	$	1,236,447	$	473,026

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20. Long-Term Debt (Details Narrative) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Refinery loan accrued interest	$ 250,070	$ 967,567
Notre Dame debt accrued interest	858,784	650,214
Construction funding accrued interest	386,695	23,578
Interest rate	6.00%
Capital leases	$ 2,119	$ 6,237
Effective rate	5.50%

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25. Stock Options (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Issuance of restricted common stock expense	$ 84,500
Common stock reserved for issuance upon exercise of outstanding options	14,642

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
REVENUE FROM OPERATIONS
Refined product sales	$ 351,665,234
Pipeline operations	406,812
Oil and gas sales	22,668
Total revenue from operations	352,094,714
COST OF OPERATIONS
Cost of refined products sold	342,035,755
Refinery operating expenses	8,603,155
Pipeline operating expenses	391,169
Lease operating expenses	57,122
General and administrative expenses	2,076,946	645,444
Depletion, depreciation and amortization	1,622,864	17,684
Abandonment expense	1,184,549
Impairment expense	9,435,745
Bad debt expense	9,508
Accretion expense	105,032
Loss on disposal of property and equipment	5,665
Total cost of operations	365,527,510	663,128
Loss from operations	(13,432,796)	(663,128)
OTHER INCOME (EXPENSE)
Net tank rental revenue	534,047	874,421
Interest and other income	21,940	23,901
Interest expense	(954,579)	(51,340)
Total other income (expense)	(398,592)	846,982
Income (loss) from continuing operations before income taxes	(13,831,388)	183,854
Tax expense
Current	(9,678)
Deferred
Income tax expense	(9,678)
Income (loss) from continuing operations, net of tax	(13,841,066)	183,854
Loss from discontinued operations, net of tax	4,443,566
Net income (loss)	$ (18,284,632)	$ 183,854
Basic earnings (loss) per common share
Continuing operations	$ (1.35)	$ 0.02
Discontinued operations	$ (0.43)
Basic earnings (loss) per common share	$ (1.78)	$ 0.02
Diluted earnings (loss) per common share
Continuing operations	$ (1.35)	$ 0.02
Discontinued operations	$ (0.43)
Diluted earnings (loss) per common share	$ (1.78)	$ 0.02
Weighted average number of common shares outstanding:
Basic	10,284,152	8,426,456
Diluted	10,284,152	8,426,456

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5. Lazarus Refining & Marketing, LLC (LRM) Acquisition

12 Months Ended

Dec. 31, 2012

Notes to Financial Statements

5. Lazarus Refining & Marketing, LLC (LRM) Acquisition

Effective October 1, 2012, we acquired 100% of the issued and outstanding membership interest of LRM, a Delaware limited liability company and a wholly-owned subsidiary of LEH pursuant to an Assignment Agreement. The acquisition was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of LRM were transferred at their carrying amounts at the date of transfer and the results of operations are included for the twelve months ended December 31, 2012. LRM did not have significant assets, liabilities or results of operations for the twelve months ended December 31, 2011. Assets and liabilities included in the consolidated balance sheets were $100,285 and $499,591, respectively, as of December 31, 2012. LRM markets petroleum storage and terminaling services at the Nixon Facility.

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4. LE Acquisition

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

4. LE Acquisition

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

LE owns a petroleum refinery located in Nixon, Wilson County, Texas (the “Nixon Facility”). The processing plant at the Nixon Facility is currently in a recommissioning phase and has not yet reached its full operational capacity. The tank farm has 120,000 barrels of crude oil storage capacity and 180,000 barrels of refined product storage capacity. The Nixon Facility has the capability to produce products such as Non-Road, Locomotive, and Marine Diesel Fuel (“NRLM”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil.

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

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

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

The below table summarizes the purchase price allocation of the net assets acquired and measurement period adjustments as of the acquisition date (as adjusted). The estimated fair values of the assets acquired and liabilities assumed were based on information that was available as of the acquisition date. Measurement period adjustments for Blue Dolphin were completed during 2012.

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

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

From the date of the LE Acquisition (February 15, 2012) through December 31, 2012, Blue Dolphin’s revenue and net loss from continuing operations included in the consolidated statements of operations for the twelve month period ended December 31, 2012, was $429,480 and $13,078,963, respectively.

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Supplemental Pro Forma Information

The following pro forma condensed consolidated statements of operations for the twelve months ended December 31, 2012 and 2011 consolidate the historical consolidated statements of operations of Blue Dolphin and LE giving effect to the LE Acquisition as if it had occurred on January 1, 2011. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only:

	Twelve Months Ended December 31, 2012
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Refined product sales	$	-		$	351,665,234		$	351,665,234
Pipeline operations		446,236			-			446,236
Oil and gas sales		28,957			-			28,957
Total revenue from operations		475,193			351,665,234			352,140,427
COST OF OPERATIONS
Cost of refined products sold		-			342,035,755			342,035,755
Refinery operating expenses		-			8,603,155			8,603,155
Pipeline operating expenses		450,634			-			450,634
Lease operating expenses		66,122			-			66,122
Abandonment expense		1,184,549			-			1,184,549
Depletion, depreciation and amortization		571,164			1,082,124			1,653,288
Impairment of oil and gas properties		9,435,745			-			9,435,745
Bad debt expense		9,508			-			9,508
General and administrative expenses		1,954,196			295,694			2,249,890
Accretion expense		115,812			-			115,812
Gain on sale of property and equipment		-			5,665			5,665
Total cost of operations		13,787,730			352,022,393			365,810,123
Loss from operations		(13,312,537	)		(357,159	)		(13,669,696	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			534,047			534,047
Interest and other income		9,720			13,059			22,779
Interest expense		(2,529	)		(952,050	)		(954,579	)
Total other income (expense)		7,191			(404,944	)		(397,753	)
Loss before income taxes		(13,305,346	)		(762,103	)		(14,067,449	)
Income tax expense		(9,678	)		-			(9,678	)
Loss from continuing operations, net of tax		(13,315,024	)		(762,103	)		(14,077,127	)
Loss from discontinued operations, net of tax		(4,445,433	)		-			(4,445,433	)
Net loss	$	(17,760,457	)	$	(762,103	)	$	(18,522,560	)

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

	Twelve Months Ended December 31, 2011
	Historical						Proforma
	Blue Dolphin			LE			Consolidated
REVENUE FROM OPERATIONS
Pipeline operations	$	931,500		$	-		$	931,500
Oil and gas sales		1,342,718			-			1,342,718
Total revenue from operations		2,274,218			-			2,274,218
COST OF OPERATIONS
Pipeline operating expenses		1,008,859			-			1,008,859
Lease operating expenses		1,174,252			-			1,174,252
Depletion, depreciation and amortization		591,927			17,684			609,611
General and administrative expenses		1,574,364			645,444			2,219,808
Accretion expense		131,690			-			131,690
Total cost of operations		4,733,798			663,128			5,396,926
Gain on sale of property and equipment		3,081,053			-			3,081,053
Income (loss) from operations		621,473			(663,128	)		(41,655	)
OTHER INCOME (EXPENSE)
Net tank rental revenue		-			874,421			874,421
Interest and other income		17,383			23,901			41,284
Interest expense		-			(51,340	)		(51,340	)
Total other income		17,383			846,982			864,365
Income before income taxes		638,856			183,854			822,710
Income tax expense		(20,921	)		-			(20,921	)
Net income	$	617,935		$	183,854		$	801,789

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

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16. Note Payable

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Note Payable

Notes payable at December 31, 2012 and 2011 was $43,941 and $46,318, respectively.

In January 2010, LE issued a $100,000 short-term note as payment for financing costs. The unsecured note, which bears interest at 18% and was originally due in January 2012, has been extended to June 2013. The balance on this note at December 31, 2012 and 2011 was $39,866 and $46,318, respectively.

In March 2012, LE acquired two used trucks for use at the Nixon Facility under a short-term note payable. The unsecured note bears interest at 5%. The balance on this note at December 31, 2012 was $4,075.

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12. Inventories

12 Months Ended

Dec. 31, 2012

Inventories

12. Inventories

Inventory balances consisted of the following:

	December 31,		December 31,
	2012		2011
Low-sulfur diesel	$	397,240	$	2,193,864
Naphtha		1,562,055		1,067,011
Atmospheric gas oil		322,356		1,010,877
Other liquids		-		64,486
Propane		-		59,599
Crude		19,041		134,289
Supplies		-		3,835
	$	2,300,692	$	4,533,961

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22. Commitments and Contingencies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]
Advances and accrued interest	$ 5,206,175
Agreement net deficit amount	659,883
Principal balance outstanding on Refinery Loan	9,298,183
Refinery loan payment	$ 287,091

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Refined Petroleum Products and Crude Oil Inventory Risk Management

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

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

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

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

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As of December 31, 2012, 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):	2012		2013		2014		2015
Refined petroleum products and crude oil -
net short (long) positions		30,000		-		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in the consolidated balance sheets at December 31, 2012 and 2011:

		Fair Value
		December 31,		December 31,
Liabilities Derivatives	Balance Sheets Location	2012		2011
	Accrued expenses and other
Commodity contracts	current liabilities	$	136,100	$	-

The following table provides the effect of derivative instruments on the consolidated statements of operations for the twelve months ended December 31, 2012 and 2011:

		Gain (Loss) Recognized
		December 31,			December 31,
Derivatives	Statements of Operations Location	2012			2011
Commodity contracts	Cost of refined products sold	$	(136,100	)	$	-

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7. Fair Value Measurement (Details) (USD $)	Dec. 31, 2012
Financial liabilties:
Commodity contracts	$ 136,100
FairValueInputsLevel1Member
Financial liabilties:
Commodity contracts	136,100
FairValueInputsLevel2Member
Financial liabilties:
Commodity contracts
FairValueInputsLevel3Member
Financial liabilties:
Commodity contracts

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6. Business Segment Information

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Business Segment Information

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

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

Twelve Months Ended December 31, 2012
	Segment
						Oil and Gas
	Refinery		Pipeline			Exploration &			Corporate &
	Operations		Transportation			Production			Other(1)			Total
Revenue	$	351,665,234	$	406,812		$	22,668		$	-		$	352,094,714
Operation cost(2)	$	350,940,269	$	8,676,242		$	2,018,126		$	2,270,009			363,904,646
Other non-interest income	$	534,047		-			-			-			534,047
EBITDA	$	1,259,012	$	(8,269,430	)	$	(1,995,458	)	$	(2,270,009	)
Depletion, depreciation and
amortization													(1,622,864	)
Other income (expense), net													(932,639	)
Loss from continuing operations,
before income taxes												$	(13,831,388	)
Loss from discontinued operations												$	(4,443,566	)
Capital expenditures	$	2,852,460	$	-		$	-		$	-		$	2,852,460
Identifiable assets(3)	$	52,745,767	$	1,861,055		$	48,247		$	1,726,854		$	56,381,926

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)	General and administrative costs are allocated based on revenue. In addition, the effect of the economic hedges on our refined petroleum products, executed by Genesis, is included within operation cost of our Crude Oil and Condensate Processing group. Cost of refined products sold includes a realized loss of $90,507 and an unrealized gain of $136,100 for the twelve months ended December, 2012.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Segment financials for the twelve months ended December 31, 2011 (and at December 31, 2011) were as follows:

	Twelve Months Ended December 31, 2011
	Segment
	Crude Oil				Oil and Gas
	and Condensate		Pipeline		Exploration &		Corporate &
	Processing		Transportation		Production		Other(1)		Total
Revenue	$	-	$	-	$	-	$	-	$	-
Operation cost(2)		645,444		-		-		-		645,444
Other non-interest income		874,421		-		-		-		874,421
EBITDA	$	228,977	$	-	$	-	$	-
Depletion, depreciation and
amortization										(17,684	)
Other income (expense), net										(27,439	)
Income from continuing operations
before income taxes									$	183,854
Capital expenditures	$	3,507,850	$	-	$	-	$	-	$	3,507,850
Identifiable assets(3)	$	38,144,056	$	-	$	-	$	-	$	38,144,056

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

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7. Fair Value Measurement

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurement

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

The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at December 31, 2012 and 2011 due to their short-term maturities. The fair value of our longer term debt for the twelve months ended December 31, 2012 and 2011 was $15,806,477 and $14,294,603, respectively. The following table represents our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and the basis for that measurement:

			Fair Value Measurement at December 31, 2012 Using
Financial assets:	Carrying Value as at December 31, 2012		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	$	136,100	$	136,100	$	-	$	-

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

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9. Concentration of Risk

12 Months Ended

Dec. 31, 2012

Risks and Uncertainties [Abstract]

9. Concentration of Risk

Key Supplier. GEL is the exclusive supplier of crude oil to the Nixon Facility pursuant to the Crude Supply Agreement, which expires on August 12, 2014.

Significant Customers. Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. For the twelve months ended December 31, 2012, our four largest customers accounted for approximately 84% of our refined petroleum products sales.

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

	December 31,			December 31,
	2012			2011
Low-sulfur diesel		48.7	%		-
Naphtha		26.2	%		-
Atmospheric gas oil		25.1	%		-
		100.0	%		-

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 2) (Commodity Contracts, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Commodity Contracts
Cost of refined products sold	$ (136,100)

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23. Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Leases Details
Rent Expense	$ 107,609	$ 110,313

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10. Prepaid Expenses and Other Current Assets (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Prepaid Expenses And Other Current Assets Details
Prepaid insurance	$ 185,814	$ 27,100
Employee advances	22,500	25,083
Property insurance		3,741
Workers compensation insurance		2,789
Prepaid loan closing fees	20,000
Prepaid Expenses, Net	$ 228,314	$ 58,713

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8. Refined Petroleum Products and Crude Oil Inventory Risk Management (Details 1) (Commodity Contracts, USD $)	Dec. 31, 2012	Dec. 31, 2011
Commodity Contracts
Accrued expenses and other current liabilities	$ 136,100

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3. Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Basis of presentation

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

Use of Estimates

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

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash

Restricted cash was $89,593 and $192,004 at December 31, 2012 and 2011, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. At December 31, 2012 and 2011, we had uninsured balances of $170,896 and $0, respectively.

We had 4 customers that accounted for approximately 84% of our total revenue for the twelve months ended December 31, 2012. These 4 customers represented approximately $11.4 million of accounts receivable at December 31, 2012.

Inventory

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

Price-Risk Management Activities

In May 2012, we implemented an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Accordingly, even though such hedge positions are direct contractual obligations of Genesis and not us, we nevertheless record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the years ended December 31, 2012 and 2011.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  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 uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Operations associated with Indonesia were discontinued in 2012. See “Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations. The estimated fair values of our AROs related to our oil and gas properties were recorded in connection with the LE Acquisition.

Pipelines and Facilities Assets. Pipelines and facilities assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded in connection with the LE Acquisition.

Construction in Progress. Construction in progress expenditures, insurance, interest and other costs related to refurbishment activities at the Nixon Facility are capitalized as incurred. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the Nixon Facility. Depreciation begins once the asset is placed in service.

Intangibles - Goodwill and Other

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

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

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

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

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

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

Impairment of Long Lived Assets. Our policy is to assess the realizability of our long-lived assets, including intangible assets, and to evaluate such assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets (or group of assets) may not be recoverable. Impairment is determined to exist if the estimated future undiscounted cash flows are less than the carrying value. Future cash flow projections include assumptions for future pipeline throughput levels, anticipated capital expenditures and the impact of cost reduction measures and the level of working capital needed to support each business. Any difference between the estimated fair value and the carrying value of the asset is recognized as an impairment. For the years ended December 31, 2012 we recognized an impairment of $7,990,025 related to our pipeline fixed assets.

Debt Issue Costs

We have debt issue costs related to certain of our long-term 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 exclusive of amortization were $675,980 at December 31, 2012 and 2011. Accumulated amortization in the amount of $143,645 and $109,847 at December 31, 2012 and 2011, respectively, are being amortized over the life of the Refinery Loan. Amortization expense, which is included in interest expense, was $8,450 for the years ended December 31, 2012 and 2011. Amortization expense was $25,349 for the years ended December 31, 2012 and 2011. See “Note (20) Long-Term Debt” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

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

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

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

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at December 31, 2012 was not material.

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

Income Taxes

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 (21) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Business Combinations

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

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

Recently Adopted Accounting Guidance

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

New Pronouncements Issued but Not Yet Effective

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

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25. Stock Options (Tables)

12 Months Ended

Dec. 31, 2012

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

Stock options activity table

At December 31, 2012, there were a total of 14,642 shares of common stock reserved for issuance upon exercise of outstanding options under the Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Options outstanding at December 31, 2011		28,887		$	13.29
Options granted		-		$	-
Options exercised		(8,163	)	$	-
Options expired or cancelled		(6,082	)	$	-
Options outstanding at December 31, 2012		14,642		$	19.67		0.9	$	-
Options exercisable at December 31, 2012		14,642		$	19.67		0.9	$	-

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14. Discontinued Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

14. Discontinued Operations

On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012. The operating results of the discontinued operations are summarized as follows:

	December 31,			December 31,
	2012			2011
Revenue	$	674,797		$	-
Lease operating expenses		788,525			-
Depletion, depreciation and amortization		124,811			-
Impairment expense		3,858,427			-
Bad debt expense		321,732			-
Accretion expense		24,868			-
Total costs and expenses		5,118,363			-
Loss from discontinued operations, net of tax	$	(4,443,566	)	$	-

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19. Impairment

12 Months Ended

Dec. 31, 2012

Notes to Financial Statements

Impairment

Due to the continued weakness in our pipeline transportation and oil and gas exploration production business segments and the uncertainty of the timing and speed of recovery, we recorded an impairment of $9,435,745 for the twelve months ended December 31, 2012. The impairment charge in the period consisted of $1,445,720 related to goodwill, 100% of which was associated with our pipeline transportation and oil and gas exploration production business segments, and $7,990,025 related to our pipeline fixed assets.

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23. Leases (Tables)

12 Months Ended

Dec. 31, 2012

Leases Tables

Rent expense of office lease

Rent expenses for the office lease provides for periodic rent escalations or rent holidays over the term of the lease, which is recognized on a straight-line basis. Rent expense for the office lease was as follows:

Years Ended
December 31,
2012	$	107,609
2011	$	110,313

Future minimum lease payments

The following is a schedule of future minimum lease payments under the lease exceeding one year at December 31, 2012:

Years Ending December 31,	Future Minimum Lease Payments
2013		112,206
2014		113,558
2015		113,558
2016		113,558
2017		47,316
	$	500,196

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11. Deposits (Tables)

12 Months Ended

Dec. 31, 2012

Deposits Tables

Deposit balances

Deposit balances consisted of the following:

	December 31,		December 31,
	2012		2011
Utility deposits	$	36,500	$	36,500
Equipment deposits		124,526		124,526
Tax bonds		792,000		312,000
Purchase option deposits		283,421		-
Deposits	$	1,236,447	$	473,026

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Condensed Consolidated Statements of Stockholders' Equity (USD $)	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Beginning Balance, amount at Dec. 31, 2010	$ 84,265	$ 17,302,124	$ (1,908,151)	$ 15,478,238
Beginning Balance, shares at Dec. 31, 2010	8,426,456
Net loss			183,854	183,854
Ending Balance, amount at Dec. 31, 2011	84,265	17,302,124	(1,724,303)	15,662,086
Beginning Balance, shares at Dec. 31, 2011	8,426,456
Common stock issued for acquisition, shares	2,098,390
Common stock issued for acquisition, amount	20,984	18,025,170		18,046,154
Common stock issued for services, shares	30,288
Common stock issued for services, amount	303	183,197		183,500
Common stock issued to exercise options, shares	8,163
Common stock issued to exercise options, amount	81	19,919		20,000
Conversion of LE's related party accounts payable to equity on acquisition		993,732		993,732
Net loss			(18,284,632)	(18,284,632)
Ending Balance, amount at Dec. 31, 2012	$ 105,633	$ 36,524,142	$ (20,008,935)	$ 16,620,840
Ending Balance, shares at Dec. 31, 2012	10,563,297

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24. Earnings per share (Details Narrative)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share Details Narrative
Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,284,152	8,426,456

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3. Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Significant Accounting Policies

 (3) Significant Accounting Policies

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

Use of Estimates

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

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash

Restricted cash was $89,593 and $192,004 at December 31, 2012 and 2011, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

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

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

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. At December 31, 2012 and 2011, we had uninsured balances of $170,896 and $0, respectively.

We had 4 customers that accounted for approximately 84% of our total revenue for the twelve months ended December 31, 2012. These 4 customers represented approximately $11.4 million of accounts receivable at December 31, 2012.

Inventory

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

Price-Risk Management Activities

In May 2012, we implemented an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Accordingly, even though such hedge positions are direct contractual obligations of Genesis and not us, we nevertheless record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.

Property and Equipment

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

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

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

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the years ended December 31, 2012 and 2011.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  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 uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Operations associated with Indonesia were discontinued in 2012. See “Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations. The estimated fair values of our AROs related to our oil and gas properties were recorded in connection with the LE Acquisition.

Pipelines and Facilities Assets. Pipelines and facilities assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded in connection with the LE Acquisition.

Construction in Progress. Construction in progress expenditures, insurance, interest and other costs related to refurbishment activities at the Nixon Facility are capitalized as incurred. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the Nixon Facility. Depreciation begins once the asset is placed in service.

Intangibles – Goodwill and Other

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

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

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

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

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

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

Debt Issue Costs

We have debt issue costs related to certain of our long-term 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 exclusive of amortization were $675,980 at December 31, 2012 and 2011. Accumulated amortization in the amount of $143,645 and $109,847 at December 31, 2012 and 2011, respectively, are being amortized over the life of the Refinery Loan. Amortization expense, which is included in interest expense, was $8,450 for the years ended December 31, 2012 and 2011. Amortization expense was $25,349 for the years ended December 31, 2012 and 2011. See “Note (20) Long-Term Debt” of this report for additional disclosures related to the Refinery Loan.

Revenue Recognition

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

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

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

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at December 31, 2012 was not material.

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

Income Taxes

We 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 (21) Income Taxes” for further details.

Impairment or Disposal of Long-Lived Assets

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

Asset Retirement Obligations

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

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

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

Derivatives

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

Computation of Earnings Per Share

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

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

Stock Based Compensation

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

Business Combinations

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

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

Recently Adopted Accounting Guidance

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

New Pronouncements Issued but Not Yet Effective

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

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6. Business Segment Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Refinery Operations
Revenues	$ 351,665,234
Operation cost	350,940,269
Other non-interest income	534,047
EBITDA	1,259,012
Capital expenditures	2,852,460
Identifiable assets	52,745,767
Pipeline Transportation
Revenues	406,812
Operation cost	8,676,242
Other non-interest income
EBITDA	(8,269,430)
Capital expenditures
Identifiable assets	1,861,055
Oil And Gas Exploration and Production
Revenues	22,668
Operation cost	2,018,126
Other non-interest income
EBITDA	(1,995,458)
Capital expenditures
Identifiable assets	48,247
Corporate and Other
Revenues
Operation cost	2,270,009
Other non-interest income
EBITDA	(2,270,009)
Capital expenditures
Identifiable assets	1,726,854
Total
Revenues	352,094,714
Operation cost	363,904,646	645,444
Other non-interest income	534,047	874,421
Depletion, depreciation and amortization	(1,622,864)	(17,684)
Other income (expense), net	(932,639)	(27,439)
Income (loss) before taxes	(13,831,388)	183,854
Loss from discontinued operations	(4,443,566)
Capital expenditures	2,852,460	3,507,850
Identifiable assets	56,381,926	38,144,056
Crude Oil And Condesate Processing
Revenues
Operation cost		645,444
Other non-interest income		874,421
EBITDA		228,977
Capital expenditures		3,507,850
Identifiable assets		$ 38,144,056

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21. Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2012
Income Taxes Details 1
Expected tax rate	34.00%
Permanent differences	(0.17%)
State tax	(0.04%)
Change in valuation allowance recognized in earnings	(33.84%)
Expected tax rate Continuing Operations	(0.05%)

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13. Property, Plant and Equipment, Net (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Property Plant And Equipment Net Details
Refinery and facilities	$ 34,000,199
Pipelines and facilities	1,233,811
Onshore separation and handling facilities	325,435
Land	577,965	104,740
Other property and equipment	577,567	217,136
Property, Plant and Equipment, Gross	36,714,977	321,876
Less: Accumulated depletion, depreciation and amortization	1,674,151	62,443
Property, Plant and Equipment less depreciation	35,040,826	259,433
Construction in Progress	821,259	32,048,496
Property, Plant and Equipment, Net	$ 35,862,085	$ 32,307,929

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20. Long-Term Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt

(20) Long-Term Debt

Our outstanding long-term debt obligations consist of notes payable, construction financing and capital leases and are as follows:

	December 31,		December 31,
	2012		2011
Refinery Loan	$	9,298,183	$	9,669,173
Notre Dame Debt		1,300,000		1,300,000
Construction and Funding Agreement		5,206,175		3,319,193
Captial Leases		2,119		6,237
		15,806,477		14,294,603
Less: Current portion of long-term debt		1,816,960		1,839,501
	$	13,989,517	$	12,455,102

The following is a schedule of future long-term debt payments:

Years Ending December 31,	Amount
2013	$	1,861,256
2014		1,972,878
2015		2,092,528
2016		718,292
2017		411,203
Subsequent to 2017		8,750,320
	$	15,806,477

Refinery Loan.  In September 2008, LE obtained a loan from First International Bank (“FIB”) in the amount of $10,000,000 (the “Refinery Loan”).  The Refinery Loan accrues interest at a rate of prime plus 2.25% (effective rate of 5.50% at December 31, 2012) and has a maturity date of October 2028.  The Refinery Loan is: (i) secured by a first lien on the Nixon Facility and general assets of LE and (ii) subject to certain restrictive financial covenants related to debt to net worth and current ratio.  Currently, we are not in compliance with certain financial covenants and, since August 2011, the Refinery Loan has been subject to a forbearance agreement (the “Forbearance Agreement”). Interest was accrued on the Refinery Loan in the amount of $250,070 and $967,567 at December 31, 2012 and 2011, respectively.

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

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

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

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

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

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

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

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

Notre Dame Debt.  LE obtained a loan in the original amount of $8,000,000 from Notre Dame Investors, Inc., which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt, which is currently in default, accrues interest at the default rate of 16% and is secured by a subordinated lien on the Nixon Facility and general assets of LE.  Interest was accrued on the note in the amount of $858,784 and $650,214 at December 31, 2012 and 2011, respectively.  There are no financial covenants associated with the Notre Dame Debt.

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

Construction and Funding Agreement. In August 2011, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations.  We started making payments under the Construction and Funding Agreement in the first quarter of 2012.  All amounts advanced under the Construction and Funding Agreement bear interest at a rate of 6% annually.  Interest totaled $386,695 and $23,578 at December 31, 2012 and 2011, 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 to the Joint Marketing Agreement, which previously added to our obligation amount under the Construction and Funding Agreement.

Capital Leases.  LE was obligated under various capital lease agreements for equipment totaling $2,119 and $6,237 at December 31, 2012 and 2011, respectively.  The capital leases require monthly payments ranging from $164 to $2,559, including imputed interest at rates ranging from 8.50% to 13.39%, and maturing at various dates through February 2014.  The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair value of the assets.  The assets are amortized over the lower of their related lease terms or their estimated productive lives.

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

	December 31,		December 31,
	2012		2011
Cost	$	9,396	$	9,396
Less: Accumulated amortization		4,541		3,602
	$	4,855	$	5,794

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18. Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligations Details
Fair value of asset retirement obligations at February 15, 2012	$ 1,294,139
Liabilities incurred
Liabilities extinguished	(361,680)
Liabilities settled	(141,099)
Accretion expense	105,032
Accretion from discontinued operations	24,868
Asset retirement obligations as of June 30, 2012	921,260
Less current portion of asset retirement obligations
Asset retirement obligations, long-term balance at June 30, 2012	$ 921,260

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

12 Months Ended

Dec. 31, 2012

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):	2012		2013		2014		2015
Refined petroleum products and crude oil -
net short (long) positions		30,000		-		-		-

Fair value amounts of derivative instruments

The following table provides the location and fair value amounts of derivative instruments that are reported in the consolidated balance sheets at December 31, 2012 and 2011:

		Fair Value
		December 31,		December 31,
Liabilities Derivatives	Balance Sheets Location	2012		2011
	Accrued expenses and other
Commodity contracts	current liabilities	$	136,100	$	-

Derivative instruments on the consolidated statements of operations

The following table provides the effect of derivative instruments on the consolidated statements of operations for the twelve months ended December 31, 2012 and 2011:

		Gain (Loss) Recognized
		December 31,			December 31,
Derivatives	Statements of Operations Location	2012			2011
Commodity contracts	Cost of refined products sold	$	(136,100	)	$	-

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13. Property, Plant and Equipment, Net

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

13. Property, Plant and Equipment, Net

Property and equipment consisted of the following:

	December 31,		December 31,
	2012		2011
Refinery and facilities	$	34,000,199	$	-
Pipelines and facilities		1,233,811		-
Onshore separation and handling facilities		325,435		-
Land		577,965		104,740
Other property and equipment		577,567		217,136
		36,714,977		321,876
Less: Accumulated depletion, depreciation and amortization		1,674,151		62,443
		35,040,826		259,433
Construction in Progress		821,259		32,048,496
Property, Plant and Equipment, Net	$	35,862,085	$	32,307,929

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