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

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

For the transition period from                      to                     .

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware		73-1268729
State or other jurisdiction		(I.R.S. Employer
of incorporation or organization		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

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

(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 o 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 o 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 o

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

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. o

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

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

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

Aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2010 was approximately $2.7 million based on the reverse stock split-adjusted closing price of $2.47 per share on the NASDAQ Capital Market.

Number of shares of Common Stock outstanding as of March 31, 2011			2,078,514

     Certain sections of the registrant’s definitive proxy statement for its 2011 Annual Meeting of Stockholders, which is to be filed with the Securities and Exchange Commission pursuant to Regulation 14A, under the Securities and Exchange Act of 1934 within 120 days of the registrant’s fiscal year ended December 31, 2010, are incorporated by reference in Part III of this report.

 

 

BLUE DOLPHIN ENERGY COMPANY
FORM 10-K REPORT INDEX

PART I
ITEM 1. BUSINESS			3
ITEM 1A. RISK FACTORS			20
ITEM 1B. UNRESOLVED STAFF COMMENTS			26
ITEM 2. PROPERTIES			26
ITEM 3. LEGAL PROCEEDINGS			27
ITEM 4. (REMOVED AND RESERVED)			27
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			28
ITEM 6. SELECTED FINANCIAL DATA			30
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			31
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			62
ITEM 9A. CONTROLS AND PROCEDURES			62
ITEM 9B. OTHER INFORMATION			63
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			63
ITEM 11. EXECUTIVE COMPENSATION			63
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			63
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			63
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			63
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			64
SIGNATURES			67
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

PART I

Forward Looking Statements. Certain of the statements included in this annual report on Form 10-K, including those regarding future financial performance or results or that are not historical facts, are “forward-looking” statements as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. The words “expect,” “plan,” “believe,” “anticipate,” “project,” “estimate,” and similar expressions are intended to identify forward-looking statements. Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) cautions readers that these statements are not guarantees of future performance or results and such statements involve risks and uncertainties that may cause actual results and outcomes to differ materially from those indicated in forward-looking statements. Some of the important factors, risks and uncertainties that could cause actual results to vary from forward-looking statements include:

	•		ability to continue as a going concern;
	•		collectability of a $2.0 million loan receivable, net of credited and recovered amounts;
	•		ability to complete a combination with one or more target businesses;
	•		ability to secure additional working capital to fund operations;
	•		ability to monetize our pipeline assets;
	•		ability to improve pipeline utilization levels;
	•		performance of third party operators for properties where we have an interest;
	•		production from oil and gas properties that we have interests in;
	•		volatility of oil and gas prices;
	•		uncertainties in the estimation of proved reserves, in the projection of future rates of production, the timing of development expenditures and the amount and timing of property abandonment;
	•		costly changes in environmental and other government regulations for which we are subject;
	•		adverse changes in the global financial markets; and
	•		potential delisting of our Common Stock by NASDAQ due to non-compliance with NASDAQ listing requirements.

Additional factors that could cause actual results to differ materially from those indicated in the forward-looking statements are discussed in Item 1A “Risk Factors.” Readers are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date hereof. We undertake no duty to update these forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us which attempt to advise interested parties of the additional factors which may affect our business, including the disclosures made under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report.

ITEM 1. BUSINESS

The Company

Blue Dolphin, a Delaware corporation, was formed in 1986 as a holding company and conducts substantially all of its operations through its subsidiaries. We are engaged in two lines of business: (i) pipeline transportation services to producers/shippers, and (ii) oil and gas exploration and production. Substantially all of our assets consist of equity interests in our subsidiaries. Our operating subsidiaries are:

	•		Blue Dolphin Pipe Line Company, a Delaware corporation;
	•		Blue Dolphin Petroleum Company, a Delaware corporation;
	•		Blue Dolphin Exploration Company, a Delaware corporation;
	•		Blue Dolphin Services Co., a Texas corporation; and
	•		Petroport, Inc., a Delaware corporation.

Our principal executive office is located at 801 Travis Street, Suite 2100, Houston, Texas, 77002, and our telephone number is (713) 568-4725. We have five (5) full-time employees and regularly use the services of two (2) consultants. Our common stock, par value $0.01 per share (“Common Stock”) is publicly traded on the NASDAQ Capital Market under the ticker symbol “BDCO.” Our website address is http://www.blue-dolphin.com.

Certain terms that are commonly used in the oil and gas industry, including terms that define our rights and obligations with respect to our interests in properties, are defined in the “Glossary of Certain Oil and Gas Terms” of this report.

Recent Developments

NASDAQ Listing. On March 16, 2010, we were notified by NASDAQ that our Common Stock was subject to delisting for failure to comply with the minimum bid price listing requirement. On April 15, 2010, we submitted a compliance plan, which outlined a reverse stock split, to a NASDAQ Listing Qualifications Panel (the “Panel”) for meeting the minimum bid requirement. As permitted under NASDAQ’s listing rules, on May 14, 2010, the Panel granted us an extension for continued listing until compliance with the minimum bid requirement was fully demonstrated. On August 4, 2010, following the effectiveness of our reverse stock split, we received confirmation from NASDAQ that we had cured our minimum bid price deficiency.

On May 20, 2010, we were notified by NASDAQ that our stockholders’ equity had fallen below the minimum listing requirement. On May 27, 2010, we submitted a compliance plan to the Panel to cure the stockholders’ equity deficiency. The compliance plan provided a pro forma calculation of the impact of our working interest in the North Sumatra Basin-Langsa Field, as well as outlined our efforts to collect on an outstanding loan receivable. As permitted under NASDAQ Listing Rules, on June 23, 2010, the Panel granted us an extension for continued listing until compliance with the stockholders’ equity requirement was fully demonstrated. On November 24, 2010, we received confirmation from NASDAQ that we had cured our stockholders’ equity deficiency. The Panel will monitor our continued compliance with the stockholders’ equity rule for a period of one year. In the event we fall out of compliance during the monitoring period, the Panel may, at its discretion, delist our Common Stock.

Reverse Stock Split. On March 16, 2010, our Board of Directors (the “Board”) approved and authorized, subject to stockholder approval, implementation of a reverse stock split of our Common Stock at a ratio within a range from 1 for 5 (1:5) to 1 for 10 (1:10), at the discretion of the Board, at any time prior to September 1, 2010. The reverse stock split was approved by our stockholders on June 9, 2010. The Board set the reverse stock split ratio at 1 for 7 (1:7) on June 30, 2010. The effective date for the reverse stock split was July 16, 2010. No fractional shares were issued in connection with the reverse stock split. Each holder of Common Stock who would otherwise be entitled to receive a fractional share of Common Stock was, in lieu of such fractional share, was paid in cash at fair market value. The Board elected not to alter the number of authorized shares or change the par value of the Common Stock, such number of authorized shares remaining at 100,000,000 shares and such par value remaining a $0.01 per share. Earnings per share, common stock outstanding and weighted average common stock outstanding as referred to in these condensed consolidated financial statements have been restated, where applicable, to give retroactive effect of the reverse stock split.

Outstanding Loan Receivable. In the second quarter of 2010, we began foreclosure proceedings on the collateral and guaranty securing a $2.0 million loan, net of credited and recovered amounts (the “Loan”), made to Lazarus Louisiana Refinery II, LLC (“LLRII” or the “Borrower”). The Loan, made on July 31, 2009 and due on January 31, 2010, is secured by (i) a first lien on property owned by Lazarus Environmental, LLC (“LEN”), (ii) a second lien on property owned by LLRII (collectively the “Collateral”) and (iii) a guaranty from Lazarus Energy Holdings, LLC (“LEH”) (the “Guaranty”). Although we agreed to forbear repayment of the loan receivable until June 11, 2010, the Borrower failed to satisfy certain conditions set forth in the forbearance agreement. When the Loan became due and payable under the original terms, the Borrower defaulted.

Blue Dolphin v. LLRII (State of Louisiana). The Collateral went up for auction under a Writ of Seizure and Sale issued by the 31^st Judicial District Court, Parish of Jefferson Davis, State of Louisiana on July 28, 2010. There were no bidders on the property owned by LLRII. As a credit bid against the Loan, we bid the minimum amount of $134,000 for the property owned by LEN, which consisted primarily of an inactive salt water disposal well. As there were no third-party bidders on the property owned by LEN, we acquired the property at the fair market value of $201,000.

Blue Dolphin v. LEH (State of Texas). On May 26, 2010, we filed a petition in the 129^th Judicial District, in the District Court of Harris County, State of Texas (the “Court”) alleging breach of contract and asserting our right to the unpaid principal balance and all accrued interest due and payable under the Loan. Although LEH filed a counter-claim alleging usurious interest based on a $500,000 consulting agreement made between the parties, in September 2010 we exercised our right to cure the alleged usury without having to admit guilt based on a statutory provision. In so doing, the Borrower was credited $500,000 against the outstanding principal balance, and the matter proceeded without undue delay. In response, LEH filed an amended counter-claim further alleging breach of contract under the confidentiality agreement between the parties. By order dated February 7, 2011, the Court granted a partial summary judgment on liability under the promissory note and Guaranty in favor of Blue Dolphin and against LEH and LLRII. The Court, however, deferred a ruling on the damages and attorney’s fees to be awarded. Although the parties reached an agreement regarding the amount of attorneys’ fees to be awarded, and the defendants do not dispute the calculation of damages sought by Blue Dolphin, the defendants continue to contest Blue Dolphin’s entitlement to summary judgment. On February 25, 2011, we filed a motion for entry of the partial summary judgment. On March 28, 2010, our motion for entry of the partial summary judgment was heard before the Court. The Court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against LEH and LLRII on the promissory note and Guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement.

Blue Sky Langsa Purchase. In June 2010, we signed a commitment letter with Blue Sky Langsa, Ltd. (“Blue Sky”) to acquire a 70% working interest in a Technical Assistance Contract for the Langsa area, offshore Indonesia (the “North Sumatra Basin-Langsa Field”). During the third quarter of 2010, the parties amended the terms of the commitment letter in order to carry out the transaction in two phases. Under the first phase, we acquired a 7% working interest in the North Sumatra Basin-Langsa Field under a definitive sale and purchase agreement dated July 21, 2010. The consideration paid by Blue Dolphin was 342,857 shares of Common Stock on a post reverse stock split adjusted basis. We had the option to acquire the remaining 63% working interest in the North Sumatra Basin-Langsa Field for an additional 3,085,714 shares of Common Stock on a post reverse stock split adjusted basis. We elected not to exercise the option, which expired on September 30, 2010.

Growth Strategy

Historically focused on exploration and production, we sold substantially all of our producing and gas properties in 2002 to satisfy working capital needs and to finance future asset acquisitions, primarily related to our pipeline transportation business. Due to changes in the current economic environment, over the past year and a half we began shifting our strategy from pipeline operations and activities back to focusing more on exploration and production opportunities in an effort to find a more favorable business mix, increase our reserves and improve operational income. Our strategy shift includes expansion into new geographic areas, both on and offshore, while pursuing a balanced growth strategy employing varying elements of exploration, development and acquisition activities.

Current throughput on our active pipelines is significantly below capacity. As future utilization is dependent upon the success of drilling programs around our pipelines and the attraction of new and retention of existing producers/shippers operating in the area, we are evaluating options to monetize our pipeline assets. Options may include the sale of a portion or all of our ownership interest in our pipeline

assets or a joint venture to jointly develop terminal projects based on a capital expenditure and revenue sharing formula.

See Note (8), Business Segment Information, in the “Notes to Consolidated Financial Statements” for additional information on revenue, operating income (loss), assets and depreciation, depletion and amortization on our business segments.

Pipeline Operations

We market our gathering and transportation services to producers/shippers operating in the vicinity of our pipelines, which are located offshore and onshore in the Texas Gulf Coast area. The fees we charge are based on the producer’s/shipper’s anticipated oil and gas throughput volumes, as well as their intended usage of our onshore facilities. All of our pipeline assets are held in and the operations conducted by Blue Dolphin Pipe Line Company. Unless otherwise stated herein, all gas liquid volumes transported are attributable to production from third party producers/shippers.

Pipeline Assets. The following provides a pipeline segment summary:

Pipeline										Miles of				Capacity				Storage				Average Throughput
Segment		Market				Ownership				Pipeline				(MMcf/d)				(Bbls)				(MMcf/d)
																						2010				2009				2008
BDPS(1)		Gulf of Mexico					83.3	%			38				180				85,000				13.7				15.5				22.6
GA 350		Gulf of Mexico					83.3	%			13				65				—				17.4				19.0				23.8
Omega(2)		Gulf of Mexico					83.3	%			18				110				—				—				—				—

•		Blue Dolphin Pipeline System (“BDPS”) — The BDPS spans approximately 38 miles from Galveston Area Block 288 offshore to our onshore facilities and the Dow Chemical Plant Complex in Freeport, Texas. We own an 83% undivided interest in the BDPS. The BDPS has an aggregate capacity of approximately 180 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. The BDPS is currently transporting an aggregate of approximately 9 Mcf of gas per day from 7 shippers, which represents 5% of throughput capacity.
•		Galveston Area Block 350 Pipeline (the “GA 350 Pipeline”) — The GA 350 Pipeline is an 8-inch, 13 mile offshore pipeline extending from Galveston Area Block 350 to an interconnect with a transmission pipeline in Galveston Area Block 391 located approximately 14 miles south of the Blue Dolphin Pipeline. Current system capacity on the GA 350 Pipeline is 65 MMcf of gas per day. We own an 83% undivided interest in the GA 350 Pipeline. The GA 350 Pipeline is currently transporting an aggregate of approximately 14 MMcf of gas per day from 5 shippers, which represents 22% of throughput capacity.
•		Omega Pipeline — The Omega Pipeline 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. We own an 83% undivided interest in the Omega Pipeline. The Omega Pipeline is

currently inactive. Reactivation of the Omega Pipeline 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 include leasehold interests in properties located in the U.S. Gulf of Mexico and the North Sumatra Basin in offshore Indonesia. Our leasehold interests, which are held in and the operations conducted by Blue Dolphin Petroleum Company, are subject to royalty and overriding royalty interests. We evaluate and manage oil and gas properties giving consideration to geography, reserve life and hydrocarbon mix based on seismic and other data.

Exploration and Production Assets. The following provides an oil and gas property summary:

				Approximate Working /
Field		Operator		Royalty Interest
U.S. Gulf of Mexico:
Galveston Area Block 321		Maritech Resources, Inc.		0.5%
High Island Block 115		Rooster Petroleum, LLC		2.5%
High Island Block 37		Hilcorp Energy Company		2.8%
Indonesia:
North Sumatra Basin-Langsa Field		Blue Sky Langsa, Ltd.		7.0%

•		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 block contains one active well, the A-4 Well. We own a 0.5% overriding royalty interest in the well. The lease is operated by Maritech Resources. The A-4 Well is currently producing approximately 1.2 MMcf of gas per day and 110 barrels of oil per day.
•		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 block contains one active well, the B-1 ST2 Well. We own a 2.5% working interest in a single production zone in the well. The lease is operated by Rooster Petroleum, LLC. The B-1 ST2 Well is currently producing approximately 4.2 MMcf of gas per day.
•		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 one active well, the A-2 Well, and one inactive well, the B-1 Well. We own an approximate 2.8% working interest in this lease that covers 5,760 acres. The lease is operated by Hilcorp Energy Company. The A-2 Well is currently producing approximately 0.8 MMcf of gas per day.
•		North Sumatra Basin-Langsa Field — Located in offshore Indonesia, the North Sumatra Basin-Langsa Field covers approximately 77 square kilometers and contains two oil fields in waters less than 325 feet deep. Four wells have been completed in the Malacca Formation — one active, the H-4 Well, and three inactive. Production is gathered via a floating production storage and offloading (FPSO) vessel operated by Mitsui Ocean Development & Engineering Co., Ltd. We own a 7.0% working interest in the oil field. The H-4 Well is currently producing approximately 430 barrels of oil per day.

As of December 31, 2010, there were no drilling oriented activities of material importance associated with our exploration and production assets.

Productive Wells and Acreage. The following table sets forth our ownership interest at December 31, 2010, 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.

Productive Wells

		Oil								Natural Gas								Total
		Gross				Net				Gross				Net				Gross				Net
U.S. Gulf of Mexico
Working Interest			—				—				2.0				0.1				2.0				0.1
Royalty Interest			—				—				1.0				0.1				1.0				0.1
Indonesia
Working Interest			1.0				0.1				—				—				1.0				0.1
			1.0				0.1				3.0				0.2				4.0				0.3

The following table sets forth the approximate developed and undeveloped acreage that we held as leasehold interest at December 31, 2010. 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 and natural gas, regardless of whether or not such acreage contains proved reserves.

Acreage

		Developed								Undeveloped								Total
		Gross				Net				Gross				Net				Gross				Net
U.S. Gulf of Mexico			17,280				264				—				—				17,280				264
Indonesia			3,108				218				15,919				1,114				19,027				1,332
			20,388				482				15,919				1,114				36,307				1,596

Estimated Proved Reserves and Future Net Cash Flows. Our proved reserve estimates for oil and natural gas were prepared by William J. Driscoll, an independent geologist, in accordance with the generally accepted petroleum engineering and evaluation principles and most recent definitions and guidelines established by the SEC. A copy of Mr. Driscoll’s summary reserve report is filed as an exhibit to this report. All reserve definitions contained herein are in accordance with the SEC’s Rule 4-10(a)(1)-(32) of Regulation S-X.

The quantities of proved oil and gas reserves presented below include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions. Therefore, proved reserves are limited to those quantities that are believed to be recoverable at prices and costs, and under regulatory practices and technology, existing at the time of the estimate. Accordingly, changes in oil and gas prices, operation and development costs, regulations, technology, future production and other factors, many of which are beyond our control, could significantly affect the estimates of proved reserves and the discounted present value of future net revenue attributable thereto.

Estimates of production and future net revenue cannot be expected to represent accurately the actual production or revenue that may be recognized with respect to oil and gas properties or the actual present market value of such properties. See Note (9), Supplemental Oil and Gas Information, in the “Notes to Consolidated Financial Statements” for further information concerning our proved reserves, changes in proved reserves, estimated future net revenue and costs incurred in our oil and gas activities and the discounted present value of estimated future net revenue from our proved reserves.

Proved Undeveloped Reserves. We had total estimated proved undeveloped reserves of 104 Mbbls and 0 Mbbls as of December 31, 2010 and 2009, respectively. This increase was due to our 2010 acquisition of the North Sumatra Basin-Langsa Field. During 2010, we did not convert any proved undeveloped reserves to proved developed reserves. At December 31, 2010, no material amounts of proved undeveloped reserves remain undeveloped for five years or more after they were initially disclosed as proved undeveloped reserves.

The following table presents the estimates of proved reserves (as hereinafter defined) and the discounted present value of future net revenue or expenses from proved reserves after income taxes to our net interest in oil and gas properties as of December 31, 2010. The discounted present value of future net revenue or expenses is calculated using the SEC Method (defined below) and is not intended to represent the current market value of the oil and gas reserves we own.

Proved Natural Gas and Oil Reserves
as of December 31, 2010

										Discounted
										Present Value
										of Future Net
										Cash Inflows
		Net Oil Reserves				Net Gas Reserves				(Outflows)(1)
		(Mbbls)				(MMcf)				(in thousands)
Proved Developed
Galveston Area Block 321			0.2				9			$	47
High Island Block 115			—				131				297
High Island Block 37			—				15				(48	)
North Sumatra Basin-Langsa Field			29.9				—				276
Total Proved Reserves			30.1				155			$	572
Proved Undeveloped
Galveston Area Block 321			—				—			$	—
High Island Block 115			—				—				—
High Island Block 37			—				—				—
North Sumatra Basin-Langsa Field			104.0				—				3,913
Total Proved Developed			104.0				—			$	3,913

Internal Controls over Reserve Estimates. Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent geologist under the supervision of our Chief Executive Officer. We provided the geologist with estimate preparation material such as property interests, production, current operation costs, current production prices and other information. This information is reviewed by our Chief Executive Officer and Principal Financial and Accounting Officer to ensure accuracy and completeness of the data prior to submission to our third party geologist. A letter which identifies the professional qualifications of the individual who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2010 has been filed as Exhibit 99.1 to this report.

Capital Expenditures for Proved Reserves. The following table presents information regarding the costs we expect to incur in activities associated with our proved reserves. These expenditures represent costs associated with the plugging and abandonment of wells. The information regarding proved reserves summarized in the preceding table assumes the following estimated undiscounted capital expenditures in the years indicated (amounts in thousands).

Estimated Undiscounted Capital Expenditures
Associated with Plugging and Abandonment of Wells

		Years Ending December 31,
		2011				2012				2013				2014				2015
Galveston Area Block 321			—				—				—				—				—
High Island Block A-7		$	192				—				—				—				—
High Island Block 115			—				—				—			$	38				—
High Island Block 37			—				—			$	68				—				—
North Sumatra Basin-Langsa Field			—				—				—				—				—

Remainder of Page Intentionally Left Blank

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 interest for each of the periods indicated.

Net Production, Price and Cost Data

		Years Ended December 31,
		2010								2009								2008
		U.S. Gulf								U.S. Gulf								U.S. Gulf
		of Mexico				Indonesia				of Mexico				Indonesia				of Mexico				Indonesia
Crude Oil and Condensate:
Production (Bbls)			250				8,154				250				—				117				—
Revenue		$	20,377			$	720,348			$	17,401			$	—			$	14,057			$	—
Average production per day (Bbls) (*)			0.7				22.3				0.7				—				0.3				—
Average sales price per Bbl		$	81.51			$	88.34			$	69.60			$	—			$	120.25			$	—
Natural Gas:
Production (Mcf)			31,654				—				33,630				—				44,700				—
Revenue		$	121,960			$	—			$	108,576			$	—			$	526,522			$	—
Average production per day (Mcf) (*)			86.7				—				92.1				—				122.5				—
Average sales price per Mcf		$	3.85			$	—			$	3.23			$	—			$	11.78			$	—
NGLs:
Production (gallons)			—				—				—				—				—				—
Revenue		$	—			$	—			$	—			$	—			$	—			$	—
Average production per day (gallons) (*)			—				—				—				—				—				—
Average sales price per gallon		$	—			$	—			$	—			$	—			$	—			$	—
Production Costs (**):
Per Mcfe:		$	2.19			$	12.29			$	2.71			$	—			$	5.36			$	—

Drilling, Exploration and Development Activity. During 2010, there were no wells drilled or any other exploratory or development activities conducted.

		Wells Drilled, Net Exploratory(1)
		2010				2009				2008
U.S. Gulf of Mexico
Productive			—				—				—
Dry			—				—				1
Indonesia
Productive			—				—				—
Dry			—				—				—
			—				—				1

Customers

Revenue from customers exceeding 10% of our total revenue for 2010 and 2009 was as follows:

		Natural Gas				Pipeline				Customer				% of
		and Oil Sales				Operations				Total				Total Revenue
Year Ended December 31, 2010:
Blue Sky		$	720,348			$	—			$	720,348				26	%
W&T Offshore		$	—			$	557,419			$	557,419				20	%
Maritech Resources		$	48,194			$	296,921			$	345,115				12	%
Year Ended December 31, 2009:
Gryphon Exploration Co.		$	—			$	379,828			$	379,828				20	%
W&T Offshore		$	—			$	332,396			$	332,396				18	%
Helis Oil & Gas		$	—			$	216,047			$	216,047				12	%
Maritech Resources		$	—			$	191,512			$	191,512				10	%

Markets & Competition

The price and marketability of oil and natural gas depend on a number of factors that are beyond our control. These include, among other things:

	•		the level of domestic and foreign production;
	•		actions taken by foreign oil and gas producing nations;
	•		the availability of pipelines with adequate capacity;
	•		the availability of vessels for direct shipment;
	•		lightering, transshipment and other means of transportation;
	•		the availability and marketing of other competitive fuels;
	•		fluctuating and seasonal demand for oil, natural gas and refined products; and
	•		the extent of governmental regulation and taxation (under both present and future legislation) of the production, importation, refining, transportation, pricing, use and allocation of oil, gas, refined products and alternative fuels.

In view of the many uncertainties that affect the supply and demand for crude oil, condensate, natural gas and refined petroleum products, it is impossible to accurately predict the price and marketability of our oil and natural gas production or the rates charged for our transportation and storage services. Currently, our oil production is sold at market prices at the time of lifting from our barge loading terminal, and our natural gas production is sold at market prices at the time of transmission to a major intrastate pipeline.

Vigorous competition occurs among energy providers across all energy sources. As an independent oil and gas company, in our midstream operations we face competition between producers, transporters, and distributors of oil and gas, as well as from other pipelines in the markets that we serve. The principal elements of competition among midstream companies are rates, service terms, market access, flexibility and service reliability. In the upstream sector, we compete for the acquisition of oil and natural gas properties with numerous entities, including major oil companies, independent oil and natural gas concerns and individual producers and operators, primarily on the basis of the price to be paid for such properties. Many of our competitors are large, well-established companies that have financial and other resources that are substantially greater than our own, which give them an advantage in evaluating and acquiring properties and prospects. Our future ability to engage new producers/shippers, acquire additional oil and natural gas properties and increase our reserves will depend on our ability to attract new and retain existing producers/shippers, evaluate and select suitable properties and consummate transactions in a highly

competitive environment. In addition to these factors, we must maintain experienced personnel to manage and operate our assets.

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 is a registered domain name. Previously held patents in Belgium, Denmark, France, Germany, Great Britain, Greece, Israel, Italy, the Netherlands and Spain related to an offshore storage facility and terminal were abandoned in 2010.

Governmental Regulation

We are subject to numerous environmental, legal and regulatory requirements related to our domestic and foreign operations, which can have a significant impact upon our overall operations.

Domestic. In the United States, laws and regulations under which our operations are subject include, among others:

Federal Regulation of Natural Gas Transportation. The transportation and resale of gas in interstate commerce have been regulated by the Natural Gas Act (“NGA”), the Natural Gas Policy Act (“NGPA”) and the rules and regulations promulgated by the Federal Energy Regulatory Commission (“FERC”). In the past, the federal government has regulated the prices at which gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining NGA and NGPA price and non-price controls affecting producer sales of gas, effective January 1, 1993. The Energy Policy Act of 2005 (the “2005 Energy Act”) did not alter our non-FERC-jurisdictional status, but the 2005 Energy Act greatly expanded FERC’s enforcement authority, including enforcement against market manipulation “in connection with” FERC-jurisdictional transactions. Under the 2005 Energy Act, FERC has undertaken vigorous enforcement actions against a number of entities, including those not subject to direct FERC regulation, and, in an effort to increase transparency in natural gas markets, has taken steps to require reporting by interstate, major non-interstate and potentially certain intrastate pipelines. Additionally, energy pricing has attracted renewed political interest. Therefore Congress could reenact regulatory controls in the future. The rates, terms and conditions applicable to interstate transportation of gas by pipelines are regulated by FERC under the NGA, as well as under Section 311 of the NGPA. FERC recently issued a Notice of Inquiry that could expand the reach of its regulation to aspects of intrastate pipelines. In February 2007, FERC issued a policy order acknowledging its lack of jurisdiction over offshore gathering, but stated that FERC would intervene in the event that interstate pipelines with affiliated offshore gathering lines engage in anti-competitive behavior, such as conditioning access to interstate pipeline service upon use of the affiliated gathering line.

All of our pipelines located offshore in federal waters are subject to the requirements of the Outer Continental Shelf Lands Act (“OCSLA”). FERC has stated that non-jurisdictional gathering lines, as well as interstate pipelines, are fully subject to the open access and nondiscrimination requirements of OCSLA’s Section 5, which generally authorizes FERC to insure that gas pipelines on the Outer Continental Shelf (“OCS”) will transport for non-owner shippers in a nondiscriminatory manner and will be operated in accordance with certain pro-competitive principles. Since all of our offshore pipelines fall within the exemption for feeder facilities and already operate on the basis required under OCSLA, we do not anticipate significant changes directly resulting from requirements concerning nondiscriminatory open access transportation.

Aside from the OCSLA requirements and federal safety and operational regulations, regulation of gas gathering activities is primarily a matter of state oversight. Regulation of gathering activities in Texas includes various transportation, safety, environmental and non-discriminatory purchase/transport requirements.

Federal Regulation of Oil Pipelines. Our operation of the Buccaneer Pipeline has been subject to a variety of regulations promulgated by FERC and imposed on all oil pipelines pursuant to federal law. Recently, however, oil pipelines have been granted permanent exemptions from certain FERC filing requirements because of rulings that oil pipeline transportation tariff movements of crude petroleum occurring solely on or across the OCS, or across the OCS to onshore points where transportation ends, are not subject to FERC jurisdiction under the OCSLA or the Interstate Commerce Act. In 2010, we filed our effective tariffs with FERC in electronic format in compliance with FERC’s Order No. 714 on Electronic Tariff Filings. The filing established a baseline tariff for FERC’s tariff database. Our currently effective tariffs are available on our website.

Safety and Operational Regulations. Our operations are generally subject to safety and operational regulations administered primarily by the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), the Department of Transportation, the Coast Guard, FERC and/or various state agencies. In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms and structures. Violations of lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution. Currently, we believe that we are in material compliance with the various safety and operational regulations that we are subject to. However, as safety and operational regulations are frequently changed, we are unable to predict the future effect changes in these regulations will have on our operations, if any.

Federal Oil and Gas Leases. Our U.S. Gulf of Mexico exploration and production operations are currently located on federal oil and gas leases in the OCS, which are administered by BOEMRE. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed BOEMRE regulations and orders pursuant to the OCSLA that are subject to interpretation and change by BOEMRE. For offshore operations, lessees must obtain BOEMRE approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies, such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency (the “EPA”), lessees must obtain a permit from BOEMRE prior to the commencement of drilling. BOEMRE has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. To cover the various obligations of lessees on the OCS, BOEMRE generally requires that lessees have substantial net worth or post bonds or other acceptable assurance that such obligations will be met. The cost of such bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. We are currently in compliance with the bonding requirements of BOEMRE. Under some circumstances, BOEMRE may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

With respect to our operations that are conducted on offshore federal leases, liability may generally be imposed under OCSLA for clean-up costs and pollution damages resulting from such operations, generally excluding damages caused by acts of war or the negligence of third parties. Under certain circumstances, including but not limited to conditions deemed a threat or harm to the environment, BOEMRE may also require any of our operations on federal leases to be suspended or terminated in the affected area. Furthermore, BOEMRE generally requires that offshore facilities be dismantled and removed within one year following production cessation or lease expiration.

Environmental Regulation. Our activities with respect to: (i) exploration, development and production of oil and natural gas and (ii) operation and construction of pipelines, plants and other facilities for the transportation, processing and storage of oil and natural gas are subject to stringent environmental regulation by local, state and federal authorities, including the EPA. Such regulation has increased the cost of planning, designing, drilling, operating and, in some instances, abandoning wells and related equipment. Similarly, such regulation has also increased the cost of design, construction and operation of crude oil and natural gas pipelines and processing facilities. Although we believe that compliance with existing environmental regulations will not have a material adverse effect on our operations or earnings, there can be no assurance that significant costs and liabilities, including civil and criminal penalties, will not be incurred. Moreover, future developments, such as stricter environmental laws and regulations or claims for personal injury or property damage resulting from our operations, could result in substantial costs and liabilities. In the event significant changes in environmental requirements occur, we may be required to expend amounts that are material relative to our total capital structure.

The Comprehensive Environmental Response, Compensation and Liability Act (“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 a similar state statute.

The federal Resource Conservation and Recovery Act (“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 in the future 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 exploration and production of oil and gas or used to store and maintain equipment regularly used in these operations. 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.

The Oil Pollution Act of 1990 (“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. The amount of financial responsibility required depends upon a variety of factors, including the facility or vessel type, size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, discharge history, worst-case spill potential and other considerations. We believe we have established adequate financial responsibility.

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.

The Clean Air Act and state air quality laws and regulations contain provisions that impose pollution control requirements on emissions to the air and require permits for construction and operation of certain emissions sources, including sources located offshore. We may be required to incur capital expenditures for air pollution control equipment in connection with maintaining or obtaining construction and operating permits and approvals addressing emission-related issues, although we do not expect to be materially adversely affected by such expenditures.

The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the United States and imposes permit requirements on such discharges, including discharges to wetlands. Federal regulations under the CWA and OPA require certain owners or operators of facilities that store or otherwise handle oil, to prepare and implement spill prevention, control and countermeasure plans and facility response plans relating to the possible discharge of oil into surface waters. With respect to certain of our operations, we are required to prepare and comply with such plans and to obtain and comply with permits. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide varying civil and criminal penalties and liabilities for the spills to both surface and ground waters. We believe we are in substantial compliance with the requirements of the CWA, OPA and state laws, and that any non-compliance would not have a material adverse effect on us.

Various federal and state programs regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act was passed to preserve and, where possible, restore the natural resources of the coastal zone of the United States and to provide for federal grants for state management programs that regulate land use, water use and coastal development. Under the Louisiana Coastal Zone Management Program, coastal use permits are required for certain activities, even if the activity only partially infringes upon the coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The Texas Coastal Coordination Act (“TCCA”) establishes the Texas Coastal Management Program that applies in the nineteen Texas counties that border the U.S. Gulf of Mexico and its tidal bays. The TCCA provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. These coastal programs may affect agency permitting of our facilities.

Legislation and Rulemaking. In October 1996, the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324), which amended the 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.

Federal and state legislation and regulations have been proposed that, if enacted or promulgated, could significantly affect operations in the oil and gas industry. It is not possible to predict which of the proposals, if any, will be adopted and what effect, if any, they would have on our operations. However, changes in various federal, state and local laws and regulations covering the discharge of materials into the environment, occupational health and safety issues or otherwise relating to the protection of public health and the environment, may affect our operations and costs to do business. Historically, the trend in such laws and regulations has been to place more restrictions and limitations on activities that may impact the general or work environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances, the cost of compliance of which has continued to increase. It is not possible to predict which of the proposed federal, state and local laws and regulations, if any, will be

adopted and the impact such changes may have on our operations and capital structure. We will adopt measures that maintain our compliance.

Foreign. In Indonesia, our operations are subject to the government acts, laws and regulations of the Republic of Indonesia, as well as to any international treaties or conventions to which the Republic of Indonesia is a signatory.

Employees

We have five (5) full-time employees and regularly use the services of two (2) consultants. Our employees, along with the expertise provided by our engineering and geology consultants, manage our ongoing administrative, business development and marketing operations. From time to time, we use third parties to assist with major maintenance, engineering and construction projects and activities.

Environmental

A description of our environmental activities is included in Part II, Item 8, “Financial Statements and Supplementary Data.”

Executive Officers of the Registrant

Our executive officers as of March 31, 2011 are listed below:

Name		Office		Officer Since				Age
Ivar Siem		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary			1989				64
T. Scott Howard		Treasurer and Assistant Secretary			2008				39

Ivar Siem has served as Chairman of the Board of Directors of Blue Dolphin since 1989. He was appointed as Chief Executive Officer in 2004 and as President, Assistant Treasurer and Secretary in 2010. Since 2000, he has also served as Chairman of the Board of Directors and Chief Executive Officer of Drillmar Energy Inc., a subsidiary of which filed for Chapter 11 bankruptcy reorganization in November 2009. From 1995 to 2000, he served as Chairman and director and interim President of DI Industries, which later became Grey Wolf, Inc. From 1996 to 1997, Mr. Siem also served as Chief Executive Officer of Seateam Technology ASA. From 1981 to 1995, Mr. Siem was an international consultant to companies in the energy, technology and finance industries. From 1974 to 1981, Mr. Siem held a variety of progressively responsible management positions within the Fred. Olsen group of companies, including President of Dolphin International, Inc. until it was sold in 1981. Mr. Siem began his career as a petroleum engineer for Amoco Corporation. He currently serves or has previously served on the Boards of Directors of several public and privately-held companies, including Avenir ASA, The Classical Theatre, Frupor SA, TI A/S, Siem Industries, Inc. and two of its affiliates. Mr. Siem holds a Bachelor of Science in Mechanical Engineering from the University of California, Berkeley, and has completed an executive MBA program at Amos Tuck School of Business, Dartmouth University.

T. Scott Howard was appointed as Treasurer of Blue Dolphin in 2009 and Assistant Secretary of Blue Dolphin in April 2008. He joined Blue Dolphin as Accounting Manager in 2006. From 1996 to 2006 he held a variety of management level positions: Audit Manager with DRDA, P.C., an independent public accounting firm in Houston, Texas from 2002 to 2006, Trust Officer with Frost National Bank in Houston, Texas from 2000 to 2002 and Controller for Hall’s Insurance Agency, Inc. in Dickinson, Texas from 1996 to 2000. He began his career as a Staff Accountant for Griffin, Iles, Masel & Duval, LLP, a public accounting firm, where he was employed from 1994 to 1996. Mr. Howard, who is a Certified Public Accountant in Texas, received his Bachelor of Business Administration in Accounting from St. Edward’s University.

Available Information

We make available, free of charge on or through our website (http://www.blue-dolphin.com), our annual, quarterly and current reports, and any amendments to those reports, as soon as practical after these reports are filed with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, Northeast, Washington, D.C. 20549, on official business days during the hours of 10:00 a.m. to 3:00 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at (800) SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

Information about each of our directors, as well as each of our Board’s standing committee charters, our corporate governance guidelines and our code of business conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

Glossary of Certain Oil and Gas Terms

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

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.

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

Condensate. Liquid hydrocarbons associated with the production of a primarily gas reserve.

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.

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.

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.

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

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.

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.

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.

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 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.

Reversionary Interest. A form of ownership interest in property that reverts back to the transferor after expiration of an intervening income interest or the occurrence of another triggering event.

Royalty Interest. An interest in a gas and oil property entitling the owner to a share of gas and oil production free of costs of production.

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.

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.

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

Based on our historical financials, there is uncertainty as to our ability to continue as a going concern.

As described in the report of our independent registered public accounting firm and in Note (1), Organization and Significant Accounting Policies, to the “Notes to Consolidated Financial Statements” included in this report, there is substantial doubt about our ability to continue as a going concern. We incurred a net loss of $1,022,895 for the year ended December 31, 2010. As of December 31, 2010, we had an accumulated deficit of $31,130,546. We anticipate that we will continue to incur substantial operating losses unless we are able to achieve and sustain profitability.

Our limited revenue and cash flow deficiencies raise substantial doubt as to our ability to continue as a going concern. Existing and anticipated working capital needs, lower than anticipated revenue, increased expenses and/or the inability to recover damages awarded under a partial summary judgment related to a defaulted loan could all affect our ability to continue as a going concern.

The continuation of our business is dependent upon obtaining additional financing. We will seek to raise additional working capital through private placements, sale of existing assets, public offerings, bank financing and/or advances from related parties or shareholder loans, as well as to continue evaluating potential merger and/or acquisition opportunities. There are no assurances that we will be able to raise additional capital through private placement, public offerings and/or bank financing, and this report may make it more difficult to raise such capital. Furthermore, the issuance of additional equity securities could result in a significant dilution in the equity interests of current or future stockholders. Obtaining commercial loans, assuming those loans would be available, will increase liabilities and future cash commitments. We do not currently have any arrangements in place to raise additional capital.

If the $1.7 million award under a partial summary judgment in favor of Blue Dolphin and against LEH and LLRII is not recovered, we could deplete our cash reserves by the end of the third quarter of 2011.

In the second quarter of 2010, we began foreclosure proceedings on the Collateral and Guaranty securing the Loan. The Collateral went up for auction under a Writ of Seizure and Sale issued by the 31^st Judicial District Court, Parish of Jefferson Davis, State of Louisiana on July 28, 2010. There were no bidders on the property owned by LLRII. As a credit bid against the Loan, we bid the minimum amount of $134,000 for the property owned by LEN, which consisted primarily of an inactive salt water disposal well. As there were no third-party bidders on the property owned by LEN, we acquired the property at its fair market value of $201,000.

On May 26, 2010, we filed a petition in the Court alleging breach of contract and asserting our right to the unpaid principal balance and all accrued interest due and payable under the Loan. By order dated February 7, 2011, the Court granted a partial summary judgment on liability under the promissory note and Guaranty in favor of Blue Dolphin and against LEH and LLRII. On March 28, 2010, our motion for entry of the partial summary judgment was heard before the Court. The Court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against LEH and LLRII on the promissory note and Guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement. Our cash flow projections suggest that, should the damages awarded under the partial summary judgment not be recovered, we could deplete our cash reserves by the end of the third quarter of 2011.

If we are not able to generate sufficient funds from our operations, monetize our pipeline assets, or obtain financing from other sources, we may not be able to continue our operations.

In the past four years we have used a portion of our cash reserves to fund working capital requirements that were not funded from our operations. Continued pipeline underutilization, low commodity prices, production problems, reserve declines, unfavorable drilling results and other factors beyond our control could further reduce funds from our operations. Currently, we project that our current cash reserves will be sufficient to meet our obligations through the third quarter of 2011. If we are unable to obtain additional funds, we may have to seek debt and/or equity financing to meet our working capital requirements. Our history of losses may affect our ability to raise additional capital and increase the cost and terms of obtaining such financing. In the event we are not able to raise additional capital, we may be forced to sell our assets or discontinue our operations.

We are primarily dependent on revenue from our pipeline systems and our working interests in four oil and gas producing properties.

For the year ended December 31, 2010, approximately 69% of our revenue was derived from our pipeline operations. We expect that future revenue will continue to be primarily dependent on the usage level on our pipeline systems. Various factors can influence the usage level, including the success of drilling programs in the areas near our pipelines and our ability to attract new producer/shippers. There are various pipelines in and around our pipeline systems that we vigorously compete with for new producer/shippers. There can be no assurance that we will be successful in attracting new producer/shippers to our pipeline systems.

The rate of production from oil and gas properties generally declines as reserves are depleted. Most of our working interests are held in properties located in the U.S. Gulf of Mexico where the rate of production generally declines more rapidly than in many other producing areas of the world. As the production level from these properties continues to decline, our revenue from oil and gas sales will decrease. Revenue from oil and gas sales accounted for approximately 31% and 6% of our total revenue in 2010 and 2009, respectively. Unless we are able to offset declining production revenue with revenue from interests in new oil and gas properties, increased throughput from new or existing shippers/producers or acquire other revenue generating assets at an acceptable cost, our revenue and cash flow from operations will continue to decrease and our financial condition will be materially adversely affected.

A significant decrease in exploration and production activity within the areas where our pipelines are located would adversely affect our revenue and cash flow.

Our current business model is largely dependent upon the success of exploration and production activities along our pipeline corridors, which directly impacts our throughput volume. Current throughput on our pipelines is significantly below capacity. Failure to connect new wells to our pipelines, as well as declines in production from existing wells, will result in the amount of throughput being further reduced over time.

We have no control over the many factors that affect production activity, including prevailing and projected commodity prices, oil and gas demand, reserve levels, geological considerations, governmental regulation and the availability and cost of capital. Any decrease in our pipeline throughput will negatively impact our revenue and operating income.

The global financial crisis may have an impact on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our financial condition. Additionally, the current economic situation could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact on our revenue.

If our Common Stock is delisted from trading on the NASDAQ, the market price of our Common Stock could be adversely affected.

Our Common Stock is currently listed on the NASDAQ Capital Market under the symbol “BDCO.” NASDAQ Marketplace Rules require issuers to maintain a minimum of $2.5 million in stockholders’ equity for continued listing. On May 20, 2010, we were notified by NASDAQ that our stockholders’ equity had fallen below the minimum listing requirement. On May 27, 2010, we submitted a compliance plan to the Panel to cure the stockholders’ equity deficiency. The compliance plan provided a pro forma calculation of the impact of our working interest in the North Sumatra Basin-Langsa Field, as well as outlined our efforts to collect on the outstanding loan receivable. As permitted under NASDAQ Listing Rules, on June 23, 2010 the Panel granted us an extension for continued listing until compliance with the stockholders’ equity requirement was fully demonstrated. On November 24, 2010, we received confirmation from NASDAQ that we had cured our stockholders’ equity deficiency. The Panel will monitor our continued compliance with the stockholders’ equity rule for a period of one year. In the event we fall out of compliance during the monitoring period, the Panel may, at its discretion, delist our Common Stock.

There can be no assurance that we will be successful in maintaining the listing of our Common Stock on NASDAQ. A delisting of our Common Stock from NASDAQ could adversely affect the liquidity of our Common Stock and its market price. If NASDAQ delists our Common Stock, and our Common Stock is not eligible for quotation on another market or exchange, trading of our Common Stock could be conducted in the over-the-counter market or the pink sheets. In such event, it could become more difficult to dispose of or obtain accurate price quotations for our Common Stock, and there would likely be a reduction in coverage by security analysts and the news media, all of which could cause the price of our Common Stock to decline further. If an active trading market for our Common Stock is not sustained, it will be difficult for our shareholders to sell their shares without further depressing the market price of our Common Stock. Delisting of our Common Stock could also make it more difficult to obtain financing or consummate deals for the continuation of our operations.

The geographic concentration of our assets may have a greater effect on us compared to other companies.

The majority of our assets are located in the U.S. Gulf of Mexico and Texas Gulf Coast region. As a result, we are at a greater risk of being impacted by local conditions compared to oil and gas companies that have their assets more geographically diversified. Any negative regional event, including commodity price fluctuations, natural disasters and restrictive governmental regulations could adversely impact our business.

A substantial and extended decline in the prices of oil and gas would have a material adverse effect on our operations.

As a significant portion of our reserves are natural gas, we are impacted more by changes in natural gas prices. The tightening of natural gas supplies and demand fundamentals has resulted in extremely volatile natural gas prices, and this volatility in natural gas prices is expected to continue. Our revenue, profitability, operating cash flow and potential for growth are largely dependent on prevailing oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include:

	•		U.S. weather conditions;
	•		the U.S. economy;
	•		Organization of Petroleum Exporting Countries actions;
	•		governmental regulation;
	•		political stability in the Middle East, South America and elsewhere;
	•		the foreign supply of oil and natural gas;
	•		the price of foreign imports;
	•		the availability of alternate fuel sources; and
	•		the value of the U.S. dollar in relation to other currencies.

In addition, low or declining oil and natural gas prices could have collateral effects that could adversely affect us, including the following:

	•		reducing the exploration for and development of oil and gas reserves held by third party companies around our pipeline systems;
	•		increasing our dependence on external sources of capital to meet our cash needs; and
	•		impairing our ability to obtain needed capital.

Strong competition from larger companies may negatively impact our ability to continue our operations.

The oil and gas industry is highly competitive. Our competitors include major integrated oil and gas companies, large independent energy companies, affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which possess greater financial and other resources than we do. Our ability to successfully compete in the marketplace is affected by many factors, including our ability to access capital and absorb risks. We believe these factors largely put us at a competitive disadvantage in consummating deals and acquiring new oil and gas properties.

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Estimating reserves of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, including oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

	•		the quality and quantity of available data;
	•		the interpretation of that data;
	•		the accuracy of various mandated economic assumptions; and
	•		the judgment of the persons preparing the estimate.

The proved reserve information set forth in this report is based on estimates we prepared. Estimates prepared by others might differ materially from our estimates. Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, taxes, development expenditures, abandonment costs and operating expenses most likely will vary from our estimates. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing oil and gas prices. Our reserves also may be susceptible to drainage by operators on adjacent properties.

The present value of future net cash flows will most likely not equate to the current market value of our estimated proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the historical 12-month average price (based on the first of the month pricing for the most recently ended fiscal year) and costs in effect at December 31, 2010. Actual future prices and costs may be materially different from the prices and costs we used.

We cannot control the activities on properties we do not operate.

Currently, third parties operate or control the development of the oil and gas properties in which we have an interest. As a result, we depend on these third party operators to properly conduct lease acquisition, drilling, completion and production operations. The failure of any such third party operator or drilling contractors, as well as other service providers working on their behalf, to properly perform services or to act in ways that are in our best interest, could adversely affect our interests.

We own and generally anticipate that we will continue to own substantially less than a 50% working interest in our oil and gas prospects and properties and will therefore engage in joint operations with other working interest owners. Since we own or control less than a majority of the working interest, decisions affecting our interest could be made by the owners of a majority of the working interest. For instance, if we are unwilling or unable to participate in the costs of operations approved by owners of a majority of the working interests in a well, our working interest in the well (and possibly other wells on the property) will likely be subject to contractual “non-consent penalties.” These penalties may include, full or partial forfeiture of our interest in the well or a relinquishment of our interest in production from the well in favor of the participating working interest owners until the participating working interest owners have recovered a multiple of the costs which would have been borne by us if we had elected to participate, which often ranges from 400% to 600% of such costs.

We have pursued and intend to continue pursuing acquisitions. Our business may be adversely affected if we cannot effectively integrate acquired operations.

One of our business strategies is to acquire operations and oil and gas assets that are complementary to our existing business operations. Acquiring operations and assets involves financial, operational and legal risks, including, but not limited to:

	•		inadvertently becoming subject to liabilities of the acquired company that were unknown to us at the time of the acquisition, such as later asserted litigation matters or tax liabilities;
	•		the difficulty of assimilating operations, systems and personnel of the acquired businesses; and
	•		maintaining uniform standards, controls, procedures and policies.

Competition from other potential buyers could cause us to pay a higher price than we otherwise might have paid and reduce our acquisition opportunities. We are often out-bid by larger, better capitalized companies for the acquisition opportunities that we pursue.

Operating hazards, including those specific to the marine environment, may adversely affect our ability to conduct business.

Our operations are subject to inherent risks normally associated with oil and gas operations, including, but not limited to:

	•		pipeline ruptures;
	•		sudden violent expulsions of oil, gas and mud while drilling a well, commonly referred to as a blowout;
	•		a cave in and collapse of the earth’s structure surrounding a well, commonly referred to as cratering;
	•		explosions;
	•		fires;
	•		pollution; and
	•		other environmental risks.

If any of these events were to occur, we could suffer substantial losses from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. 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.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and results of operations.

We maintain several types of insurance to cover our operations, including maritime employer’s liability and comprehensive general liability. Amounts exceeding base coverages are provided by primary and excess umbrella liability policies. We also maintain operator’s extra expense coverage, which covers the control of drilled or producing wells and re-drilling expenses, as well as pollution coverage for out of control wells.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or losses may exceed the maximum coverage amounts under our insurance policies. We do not maintain property insurance coverage on our pipelines. If a significant event occurs that is not fully insured or indemnified against, such event could materially and adversely affect our financial condition and results of operations.

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

We currently have five (5) full-time employees and regularly use the services of two (2) consultants. Success within our existing two business segments — pipeline operations and activities and oil and gas exploration and production activities — depends largely upon the efforts of certain of our executive officers, one of which has been employed by us since the early stages of our business, and continued access to the two (2) consultants, both of whom are also former employees with a long history with Blue Dolphin. The loss of services of any one of these individuals could seriously harm our business opportunities and prospects. Given our small size, our success also depends on the retention of qualified personnel in key areas. 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.

Compliance with environmental and other government regulations could be costly and could negatively impact our operations.

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

	•		require the acquisition of a permit before operations can be commenced;
	•		restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;
	•		limit or prohibit drilling and pipeline activities on certain lands lying within wilderness, wetlands and other protected areas;
	•		require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and abandoning pipelines; and
	•		impose substantial liabilities for pollution resulting from our operations.

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, including limited coverage for sudden and accidental environmental damages. However, we do not believe that insurance coverage for all environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue to operate our properties if certain environmental damages occur.

The EPA imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the EPA, could have a material adverse impact on us.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information appearing in “Item 1. Business” describing our oil and gas properties, pipelines and other assets is incorporated herein by reference.

We lease our executive offices in Houston, Texas under an operating lease expiring April 30, 2017. Our average annual lease payment under this lease is approximately $108,000.

ITEM 3. LEGAL PROCEEDINGS

In the second quarter of 2010, we began foreclosure proceedings on the Collateral and Guaranty securing the Loan:

Blue Dolphin v. LLRII (State of Louisiana). The Collateral went up for auction under a Writ of Seizure and Sale issued by the 31^st Judicial District Court, Parish of Jefferson Davis, State of Louisiana on July 28, 2010. There were no bidders on the property owned by LLRII. As a credit bid against the Loan, we bid the minimum amount of $134,000 for the property owned by LEN, which consisted primarily of an inactive salt water disposal well. As there were no third-party bidders on the property owned by LEN, we acquired the property at the fair market value of $201,000.

Blue Dolphin v. LEH (State of Texas). On May 26, 2010, we filed a petition in the Court alleging breach of contract and asserting our right to the unpaid principal balance and all accrued interest due and payable under the Loan. Although LEH filed a counter-claim alleging usurious interest based on a $500,000 consulting agreement made between the parties, in September 2010 we exercised our right to cure the alleged usury without having to admit guilt based on a statutory provision. In so doing, the Borrower was credited $500,000 against the outstanding principal balance, and the matter proceeded without undue delay. In response, LEH filed an amended counter-claim further alleging breach of contract under the confidentiality agreement between the parties. By order dated February 7, 2011, the Court granted a partial summary judgment on liability under the promissory note and Guaranty in favor of Blue Dolphin and against LEH and LLRII. The Court, however, deferred a ruling on the damages and attorney’s fees to be awarded. Although the parties reached an agreement regarding the amount of attorneys’ fees to be awarded, and the defendants do not dispute the calculation of damages sought by Blue Dolphin, the defendants continue to contest Blue Dolphin’s entitlement to summary judgment. On February 25, 2011, we filed a motion for entry of the partial summary judgment. On March 28, 2010, our motion for entry of the partial summary judgment was heard before the Court. The Court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against LEH and LLRII on the promissory note and Guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement.

ITEM 4. (REMOVED AND RESERVED)

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PART II

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

Market Price for Common Stock

Our Common Stock is quoted on the NASDAQ Capital Market under the ticker symbol “BDCO.” As of March 31, 2011, we had 292 record holders of our Common Stock. Based on the record date for our 2010 annual meeting of stockholders, which was held on May 27, 2010, we had approximately 2,000 beneficial holders of our Common Stock.

The following table sets forth, for the periods indicated, the high and low prices for our Common Stock as reported by NASDAQ. NASDAQ quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.

Quarter Ended		High(1)				Low(1)
2010
December 31		$	2.88			$	1.70
September 30		$	3.64			$	0.99
June 30		$	4.89			$	1.33
March 31		$	4.86			$	2.24
2009
December 31		$	4.34			$	2.03
September 30		$	4.06			$	2.73
June 30		$	5.53			$	2.52
March 31		$	3.15			$	1.82

We were notified by NASDAQ on March 16, 2010, that our Common Stock was subject to delisting for failure to comply with the minimum bid price requirement, and we were also notified by NASDAQ on May 20, 2010, that our Common Stock failed to meet the stockholders’ equity requirement. Both deficiencies were cured during 2010. See “Recent Developments” in “Part I, Item 1. Business” for additional information related to our efforts to achieve compliance with NASDAQ’s listing requirements.

At the recommendation of our Board, our stockholders approved a 1 for 7 (1:7) reverse stock split of our Common Stock on June 9, 2010. The effective date for the reverse stock split was July 16, 2010. See “Recent Developments” in “Part I, Item 1. Business” for additional information related to the reverse stock split.

Dividend Policy

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.

Equity Compensation Plan Information

The following table provides information for all equity compensation plans as of the fiscal year ended December 31, 2010, under which our equity securities were authorized for issuance:

Securities Authorized for Issuance under Equity Compensation Plans

Number of

Securities

Remaining Available

Number of

for Future Issuance

Securities to be

Under Equity

Issued Upon

Weighted Average

Compensation Plans

Exercise of

Exercise Price of

(Excluding

Outstanding

Outstanding

Securities

Options, Warrants

Options, Warrants

Reflected in Column

and Rights

and Rights

(a))

Plan Category

(a)

(b)

(c)

Equity compensation plans approved by security holders

30,390

$

13.29

1,107,564

Equity compensation plans not approved by security holders

—

$

0.00

—

Total

30,390

$

13.29

1,107,564

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ITEM 6. SELECTED FINANCIAL DATA

		Quarters Ended
		March 31				June 30				September 30				December 31				Total
2010
Revenue from operations:
Pipeline operations		$	429,087			$	462,392			$	502,369			$	485,038			$	1,878,886
Oil and gas sales			19,022				21,199				237,940				584,524				862,685
Total revenue from operations			448,109				483,591				740,309				1,069,562				2,741,571
Cost of operations:
Pipeline operating expenses			286,988				325,323				243,531				242,755				1,098,597
Lease operating expenses			21,188				7,824				221,019				423,737				673,768
Depletion, depreciation and amortization			117,846				128,855				217,105				155,523				619,329
Impairment of oil and gas properties			—				—				—				—				—
Recovery of allowance for doubtful loan receivable			—				—				(201,000	)			—				(201,000	)
General and administrative expenses			479,222				359,027				306,288				283,266				1,427,803
Stock based compensation			40,320				13,440				—				—				53,760
Accretion expense			29,058				29,057				30,563				31,316				119,994
Total cost of operations			974,622				863,526				817,506				1,136,597				3,792,251
Other income (expense), including income tax expense			759				9,998				8,115				8,913				27,785
Net loss		$	(525,754	)		$	(369,937	)		$	(69,082	)		$	(58,122	)		$	(1,022,895	)
Loss per share:
Basic and diluted		$	(0.26	)		$	(0.22	)		$	(0.04	)		$	(0.03	)		$	(0.55	)
2009
Revenue from operations:
Pipeline operations		$	514,759			$	548,636			$	442,249			$	361,327			$	1,866,971
Oil and gas sales			21,946				44,075				42,269				17,687				125,977
Total revenue from operations			536,705				592,711				484,518				379,014				1,992,948
Cost of operations:
Pipeline operating expenses			466,260				491,461				309,695				247,946				1,515,362
Lease operating expenses			48,031				674				29,731				16,705				95,141
Depletion, depreciation and amortization			128,913				134,227				133,362				120,840				517,342
Impairment of oil and gas properties			203,110				—				—				—				203,110
Allowance for doubtful note receivable, net of consulting agreement			—				—				—				1,500,000				1,500,000
General and administrative expenses			602,194				650,754				372,159				364,925				1,990,032
Stock based compensation			62,644				40,320				62,562				39,320				204,846
Accretion expense			27,918				27,919				27,586				27,420				110,843
Total cost of operations			1,539,070				1,345,355				935,095				2,317,156				6,136,676
Other income (expense), including income tax expense			2,356				2,395				129,191				(127,106	)			6,836
Net loss		$	(1,000,009	)		$	(750,249	)		$	(321,386	)		$	(2,065,248	)		$	(4,136,892	)
Loss per share:
Basic and diluted		$	(0.60	)		$	(0.45	)		$	(0.19	)		$	(1.22	)		$	(2.46	)

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 “Item 1, Business” and “Item 8, Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements.”

Executive Summary

We are engaged in two lines of business: (i) pipeline transportation services to producer/shippers, and (ii) oil and gas exploration and production. Our pipeline assets are located offshore and onshore in the Texas Gulf Coast area and our leasehold interests in properties are located in the U.S. Gulf of Mexico and the North Sumatra Basin in offshore Indonesia. Our goal is to create greater long-term value for our stockholders by increasing reserves and improving operational income while pursuing a balanced growth strategy employing varying elements of exploration, development and acquisition activities.

Pipeline Operations.

•

BDPS — The BDPS is currently transporting an aggregate of approximately 9 MMcf of gas per day from 7 shippers, which represents 5% of throughput capacity.

•

GA 350 Pipeline — The GA 350 Pipeline is currently transporting an aggregate of approximately 14 MMcf of gas per day from 5 shippers, which represents 22% of throughput capacity.

Exploration and Production.

•

Galveston Area Block 321 — The A-4 Well is commingled in the 5,400’ and 5,300’ sands. Once this commingled completion depletes, there are two upper zones up the hole with booked reserves. The A-4 Well is currently producing approximately 1.2 MMcf of gas per day and 110 barrels of oil per day.

•

High Island Block 115 — The B-1 ST2 Well resumed production in July 2010 after being shut-in since August 2009 due to production handling problems on our downstream production handling platform, High Island Block 71. The B-1 ST2 Well is currently producing approximately 4.2 MMcf of gas per day.

•

High Island Block 37 — Production from the A-2 Well was restarted in February 2009, after being shut-in since September 2008 following Hurricane Ike. The A-2 Well is currently producing approximately 0.8 MMcf of gas per day.

•

North Sumatra Basin-Langsa Field — The H-4 Well is currently producing approximately 430 barrels of oil per day.

Our pipeline assets remain significantly underutilized. Production declines, temporary stoppages or cessations of production from wells tied into our pipelines or from wells in which we have a working and overriding royalty interest, as noted herein, could have a material adverse effect on our cash flows and liquidity if the resulting revenue declines are not offset by revenue from other sources. Due to our small size, geographically concentrated asset base and limited capital resources, any negative event has the potential to have a material adverse impact on our financial condition. We are continuing our efforts to increase the utilization of our existing assets and acquire additional assets that will diversify the risks to our cash flows and be accretive to earnings.

Results of Operations

For the year ended December 31, 2010 (the “current period”), we reported a net loss of $1,022,895, compared to a net loss of $4,136,892 for the year ended December 31, 2009 (the “previous period”). For the three months ended December 31, 2010 (the “current quarter”), we reported a net loss of $58,122 compared to a net loss of $2,065,248 for the three months ended December 31, 2009 (the “previous quarter”).

2010 Compared to 2009

Revenue from Pipeline Operations. Revenue from pipeline operations increased by $11,915, or 0.6%, in the current period to $1,878,886. Revenue in the current period from the BDPS totaled approximately $1,538,000 compared to approximately $1,498,000 in the previous period primarily due to increased commodity prices on the oil sold from our Freeport facility. Daily gas volumes transported through the BDPS averaged approximately 14 MMcf of gas per day in the current period compared to approximately 16 MMcf of gas per day in the previous period. Revenue on the GA 350 Pipeline decreased by approximately $28,000 to approximately $341,000 in the current period primarily due to natural production declines. Average daily gas volumes for GA 350 transported decreased to approximately 17 MMcf of gas per day in the current period from approximately 19 MMcf of gas per day in the previous period.

Revenue from Oil and Gas Sales. Revenue from oil and gas sales increased by $736,708, or 584%, to $862,685 in the current period primarily due to the addition of production from the North Sumatra Basin-Langsa Field, as well as the B-1 ST-2 Well in High Island Block 115 coming back online after being off production for nearly a year due to production problems on the downstream production handling platform.

Our average realized gas price per Mcf in the current period was $3.85 compared to $3.23 in the previous period. The sales mix by product was 86% oil and 14% gas. Our average realized price per barrel of oil was $88.14 in the current period compared to $69.60 in the previous period. Revenue breakdown for the current period by field was approximately $48,200 for Galveston Area Block 321, $48,900 for High Island Block 115, $45,300 for High Island Block 37 and $720,300 for the North Sumatra Basin-Langsa Field.

Pipeline Operating Expenses. Pipeline operating expenses decreased by $416,765, or 28%, to $1,098,597 in the current period. The decrease was primarily due to decreases in insurance expense, storage tank repairs, leak repairs, crane repairs, and other operating expenses. The decreases were partially offset by an increase in consulting expenses.

Lease Operating Expenses. Lease operating expenses increased $578,627, or 608%, in the current period to $673,768 primarily due to the addition of expenses from the North Sumatra Basin-Langsa Field, as well as the B-1 ST-2 Well in High Island Block 115 coming back online after being off production for nearly a year due to production problems on our downstream production handling platform. Lease operating costs associated with North Sumatra Basin-Langsa Field totaled approximately $601,000 for the current period.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization increased by $101,987, or 20%, in the current period to $619,329 primarily due to the acquisition of the North Sumatra Basin-Langsa Field, with associated depletion of approximately $79,000.

Impairment of Oil and Gas Properties. We use the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances. Any excess of the net book value of our oil and natural gas properties over the

ceiling must be recognized as a non-cash impairment expense. Our ceiling for the current period was calculated using domestic prices of $79.61 per barrel of oil and $4.33 per MMbtu of gas and an international price of $80.35 per barrel of oil. As our costs fell below our ceiling limitation at March 31, 2010, June 30, 2010, September 30, 2010 and December 31, 2010, we did not have an impairment of oil and gas properties in the current period. Our ceiling for the previous period was calculated using prices of $47.19 per barrel of oil and $3.65 per MMbtu of gas. At March 31, 2009, our costs exceeded our ceiling limitation, resulting in a write-down of our oil and gas properties of $203,110.

General and Administrative Expenses and Stock Based Compensation. General and administrative expenses and stock based compensation expenses decreased by $713,315, or 33%, in the current period to $1,481,563 primarily due to decreases in officer salaries, employee related expenses, consulting fees, and office expense. The decreases were partially offset by increases in audit expense, legal fees, insurance expense and stock maintenance fees.

Recovery of Allowance for Doubtful Loan Receivable. Recovery for allowance for doubtful loan receivable increased by $201,000 in the current period primarily due to the addition of a disposal well at its fair market value of $201,000 as recovery of a previously recorded bad debt expense on the outstanding loan receivable of $2.0 million, net of credited and recovered amounts.

Three Months Ended December 31, 2010 Compared to Three Months Ended December 31, 2009

Revenue from Pipeline Operations. Revenue from pipeline operations increased by $123,711, or 34%, in the current quarter to $485,038 primarily due to an increase in oil volumes transported. Revenue in the current quarter from the BDPS increased to approximately $397,500 compared to approximately $280,000 in the previous quarter. Daily gas volumes transported on the BDPS averaged 12 MMcf of gas per day in the current quarter compared to 13 MMcf of gas per day in the previous quarter. Revenue on the GA 350 Pipeline decreased to approximately $87,500 compared to approximately $81,000 in the previous quarter due to an increase in average daily gas volumes transported of 17 MMcf of gas per day in the current quarter from 16 MMcf of gas per day in the previous quarter.

Revenue from Oil and Gas Sales. Revenue from oil and gas sales increased by $566,837 to $584,524 in the current quarter primarily as a result of the addition of production from the North Sumatra Basin-Langsa Field and the B-1 ST-2 Well in High Island Block 115, the latter of which came back online after being off production for nearly a year due to production problems on the downstream production handling platform.

Pipeline Operating Expenses. Pipeline operating expenses in the current quarter decreased by $5,191, or 2%, to $242,755.

Lease Operating Expenses. Lease operating expenses increased in the current quarter by $407,032 to $423,737 due to the addition of expenses from the North Sumatra Basin-Langsa Field, as well as the B-1 ST-2 Well in High Island Block 115 coming back online after being off production for nearly a year due to production problems on our downstream production handling platform.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization increased by $34,683, or 29%, in the current period to $155,523 primarily due to the acquisition of the North Sumatra Basin-Langsa Field.

General and Administrative Expenses and Stock Based Compensation. General and administrative expenses and stock based compensation expenses decreased by $120,979, or 30%, to $283,266 in the current quarter primarily due to decreases in officer salaries and consulting expense.

Liquidity and Capital Resources

Sources and Uses of Cash. Our primary source of cash is cash flow from operations and cash on hand. During 2010, we had negative cash flow from operations of approximately $124,953, mainly due to low utilization of our pipeline systems.

We do not enter into any hedges or any type of derivatives to offset changes in commodity prices. We also do not have any outstanding debt or a credit facility with a bank or institution that may restrict us from issuing debt or Common Stock. At December 31, 2010, our current available cash was $625,854.

		For Year Ended December 31,
		2010				2009
Cash flow from operations
Loss from operations		$	(350,812	)		$	(1,520,751	)
Change in current assets and liabilities			226,219				388,143
Total cash flow from operations			(124,593	)			(1,132,608	)
Cash outflows
Capital expenditures and advance of loan receivable			(58,719	)			(1,515,643	)
Payments on financing activities			(207,317	)			(200,142	)
Total cash outflows			(266,036	)			(1,715,785	)
Total change in cash flows		$	(390,629	)		$	(2,848,393	)

In the past three years, we have used a portion of our cash reserves to fund our working capital requirements that were not funded from operations.

Going Concern. As described in the report of our independent registered public accounting firm and in Note (1), Organization and Significant Accounting Policies, to the “Notes to Consolidated Financial Statements” included in this report, there is substantial doubt about our ability to continue as a going concern. We incurred a net loss of $1,022,895 for the year ended December 31, 2010. As of December 31, 2010, we had an accumulated deficit of $31,130,546. We anticipate that we will continue to incur substantial operating losses unless we are able to achieve and sustain profitability.

Our limited revenue and cash flow deficiencies raise substantial doubt as to our ability to continue as a going concern. Existing and anticipated working capital needs, lower than anticipated revenue, increased expenses and/or the inability to recover damages awarded under a partial summary judgment related to a defaulted loan could all affect our ability to continue as a going concern.

The continuation of our business is dependent upon obtaining additional financing. We will seek to raise additional working capital through private placements, sale of existing assets, public offerings, bank financing and/or advances from related parties or shareholder loans, as well as to continue evaluating potential merger and/or acquisition opportunities. There are no assurances that we will be able to raise additional capital through private placement, public offerings and/or bank financing, and this report may make it more difficult to raise such capital. Furthermore, the issuance of additional equity securities could result in a significant dilution in the equity interests of current or future stockholders. Obtaining commercial loans, assuming those loans would be available, will increase liabilities and future cash commitments. We do not currently have any arrangements in place to raise additional capital.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules at or before their adoption, and believe the proper implementation and consistent application of accounting rules is critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by comparatively analyzing similar situations and reviewing the accounting guidance governing them, and may consult with our independent registered independent accounting firm about the appropriate interpretation and application of these policies. Our most critical accounting policies currently relate to the accounting for the impairment of long-lived assets, which include primarily our pipeline assets, as well as the evaluation and collection of the note receivable, as of December 31, 2010 and the accounting for future asset retirement costs.

Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance on accounting for the impairment or disposal of long-lived assets, we initiate a review for impairment of our long-lived assets 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 which are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. Currently, our pipeline assets are significantly underutilized and such underutilization is an indicator of possible impairment at December 31, 2010. Accordingly, we developed future cash flows as of December 31, 2010 expected to be generated from our pipeline assets based on certain assumptions. The most significant assumption made in connection with the preparation of expected future cash flows is that pipeline throughput volumes will increase over the next few years due to increased leasing and drilling activities surrounding our pipelines from current and prospective oil and gas companies. Based on the results of the impairment test, which indicates expected future undiscounted cash flows are in excess of the pipeline assets net carrying value, no impairment was recorded at December 31, 2010.

Asset Retirement Obligations. The accounting for future abandonment costs changed in August 2001, with the adoption of FASB’s guidance on accounting for asset retirement obligations. This guidance 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. Future asset retirement costs include costs to dismantle, relocate or dispose of our offshore platforms, 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.

Accounting for Uncertainty in Income Taxes. We adopted FASB’s accounting for uncertainty in income taxes effective January 1, 2007. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. It 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 evaluation of a tax position in accordance with the guidance is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of the guidance are to be applied to all tax positions. Only tax positions that meet the more-likely-than-not recognition threshold are recognized.

The provisions of the guidance have been applied to all of our material tax positions taken from January 1, 2007 through the fiscal year ended December 31, 2010. 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 prescribed by the guidance. In addition, we 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 pronouncement.

Fair Value Measurements. On January 1, 2008, we adopted FASB’s guidance on fair value measurements, which clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. In February 2008, FASB issued a staff position that deferred the effective date of the guidance for one year for nonfinancial assets and liabilities recorded at fair value on a non-recurring basis. The effect of adoption of the guidance for financial assets and liabilities recognized at fair value on a recurring basis did not have a material impact on our financial position and results of operations.

Fair Value Option for Financial Assets and Financial Liabilities. On January 1, 2008, we adopted FASB’s guidance on the fair value option for financial assets and financial liabilities. The guidance permits companies to choose an irrevocable election to measure certain financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. We did not elect the fair value option under the guidance for any of our financial assets or liabilities upon adoption.

Recently Adopted Accounting Pronouncements

Generally Accepted Accounting Principles. In June 2009, the FASB issued guidance that established the Accounting Standards Codification as the sole source of authoritative GAAP. We updated references to GAAP in our financial statements pursuant to the provisions of FASB’s guidance. The adoption of FASB’s guidance did not impact our financial position or results of operations.

Recently Issued Accounting Pronouncements and Accounting Developments

Fair Value Measurements. In January 2010, the FASB issued guidance that requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. The

guidance is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures that are deferred to annual periods beginning after December 15, 2010. The adoption of this guidance did not have a material impact on our consolidated financial statements and we do not expect the deferral provisions to have a material impact on our consolidated financial statements.

Variable Interest Entities. In December 2009, the FASB issued revised authoritative guidance associated with the consolidation of variable interest entities. This revised guidance replaces the current quantitative-based assessment for determining which enterprise has a controlling financial interest in a variable interest entity with an approach that is now primarily qualitative. This qualitative approach focuses on identifying the enterprise that has: (i) the power to direct the activities of the variable interest entity that can most significantly impact the entity’s economic performance and (ii) the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. This revised guidance also requires an ongoing assessment of whether an enterprise is the primary beneficiary of a variable interest entity rather than a reassessment only upon the occurrence of specific events. The revised guidance is effective for financial statements issued for fiscal years beginning after November 15, 2009. The implementation of this guidance did not have any impact on our consolidated financial statements.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

None.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements:

Report of Independent Registered Public Accounting Firm			38
Consolidated Balance Sheets at December 31, 2010 and 2009			39
Consolidated Statements of Operations Years Ended December 31, 2010 and 2009			40
Consolidated Statements of Stockholders’ Equity Years Ended December 31, 2010 and 2009			41
Consolidated Statements of Cash Flows Years Ended December 31, 2010 and 2009			42
Notes to Consolidated Financial Statements			43

Remainder of Page Intentionally Left Blank

Report of Independent Registered Public Accounting Firm

The Board of Directors and
     Stockholders of Blue Dolphin Energy Company
Houston, Texas

We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and Subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s 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 of the United States. Those standards require that we plan and perform the audits 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 audits 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 consolidated financial position of Blue Dolphin Energy Company and Subsidiaries as of December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note (1), “Organization and Significant Accounting Policies”, to the notes to consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note (1), as referenced herein. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Consolidated Balance Sheets

		December 31,
		2010				2009
ASSETS
Current assets:
Cash and cash equivalents		$	625,854			$	1,016,483
Accounts receivable, net of allowance for doubtful accounts			598,391				428,124
Loan receivable, net of allowance for loan receivable			—				—
Prepaid expenses and other current assets			213,071				359,850
Total current assets			1,437,316				1,804,457
Property and equipment, at cost:
Oil and gas properties (full-cost method)			2,222,535				1,086,733
Pipelines			4,659,686				4,659,686
Onshore separation and handling facilities			1,919,402				1,919,402
Land			860,275				860,275
Other property and equipment			503,813				302,813
			10,165,711				8,828,909
Less: Accumulated depletion, depreciation and amortization			5,630,730				5,011,401
Total property and equipment, net			4,534,981				3,817,508
Other assets			9,463				9,463
Total assets		$	5,981,760			$	5,631,428
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	543,327			$	372,275
Note payable — insurance			124,936				173,479
Asset retirement obligation — current portion			192,470				—
Accrued expenses and other liabilities			2,142				8,136
Other long-term liabilities — current portion			—				25,996
Total current liabilities			862,875				579,886
Long-term liabilities:
Asset retirement obligations, net of current portion			2,535,386				2,262,018
Other long-term liabilities, net of current portion			—				—
Total long-term liabilities			2,535,386				2,262,018
Total liabilities			3,398,261				2,841,904
Commitments and contingencies
Stockholders’ equity:
Common stock ($0.01 par value, 100,000,000 shares authorized, 2,078,514 and 1,696,710 shares issued and outstanding at December 31, 2010 and 2009, respectively)			20,785				16,967
Additional paid-in capital			33,693,260				32,880,208
Accumulated deficit			(31,130,546	)			(30,107,651	)
Total stockholder’s equity			2,583,499				2,789,524
Total liabilities and stockholders’ equity		$	5,981,760			$	5,631,428

See accompanying notes to consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

		Years Ended December 31,
		2010				2009
Revenue from operations:
Pipeline operations		$	1,878,886			$	1,866,971
Oil and gas sales			862,685				125,977
Total revenue from operations			2,741,571				1,992,948
Cost of operations:
Pipeline operating expenses			1,098,597				1,515,362
Lease operating expenses			673,768				95,141
Depletion, depreciation and amortizaton			619,329				517,342
Impairment of oil and gas properties			—				203,110
Allowance for doubtful note receivable			—				1,500,000
Recovery of allowance for doubtful loan receivable			(201,000	)			—
General and administrative expenses			1,427,803				1,990,032
Stock-based compensation			53,760				204,846
Accretion expense			119,994				110,843
Total cost of operations			3,792,251				6,136,676
Loss from operations			(1,050,680	)			(4,143,728	)
Other income (expense):
Interest and other income			32,370				9,921
Total other income (expense)			32,370				9,921
Loss before income taxes			(1,018,310	)			(4,133,807	)
Income tax expense			(4,585	)			(3,085	)
Net loss		$	(1,022,895	)		$	(4,136,892	)
Loss per common share:
Basic		$	(0.55	)		$	(2.46	)
Diluted		$	(0.55	)		$	(2.46	)
Weighted average number of common shares outstanding:
Basic			1,864,354				1,683,678
Diluted			1,864,354				1,683,678

See accompanying notes to consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES

		Common								Additional								Total
		Stock				Common				Paid-In				Accumulated				Stockholders’
		Shares				Stock				Capital				Deficit				Equity
Balance at December 31, 2008			1,670,178			$	16,702			$	32,595,627			$	(25,970,759	)		$	6,641,570
Common stock issued for services			26,532				265				79,735				—				80,000
Stock-based compensation			—				—				204,846				—				204,846
Net loss			—				—				—				(4,136,892	)			(4,136,892	)
Balance at December 31, 2009			1,696,710				16,967				32,880,208				(30,107,651	)			2,789,524
Common stock issued for acquisition			342,857				3,429				682,285				—				685,714
Common stock issued for services			39,987				400				79,600				—				80,000
Stock-based compensation			—				—				53,760				—				53,760
Retirement of fractional shares			(1,040	)			(11	)			(2,593	)			—				(2,604	)
Net loss			—				—				—				(1,022,895	)			(1,022,895	)
Balance at December 31, 2010			2,078,514			$	20,785			$	33,693,260			$	(31,130,546	)		$	2,583,499

See accompanying notes to consolidated financial statements.

Remainder of Page Intentionally Left Blank

Consolidated Statements of Cash Flows

		Years Ended December 31,
		2010				2009
OPERATING ACTIVITIES
Net loss		$	(1,022,895	)		$	(4,136,892	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization			619,329				517,342
Recovery of previous allowance for doubtful loan receivable			(201,000	)			—
Impairment of oil and gas properties			—				203,110
Accretion expense			119,994				110,843
Stock-based compensation			53,760				204,846
Common stock issued for services			80,000				80,000
Allowance for doubtful note receivable, net of consulting agreement			—				1,500,000
Changes in operating assets and liabilities:
Accounts receivable			(170,267	)			14,591
Prepaid expenses and other current assets			302,949				450,013
Abandonment costs incurred			(45,525	)			(32,015	)
Accounts payable, accrued expenses and other liabilities			139,062				(44,446	)
Net cash used in operating activities			(124,593	)			(1,132,608	)
INVESTING ACTIVITIES
Advance of loan receivable			—				(1,500,000	)
Exploration and development costs			—				(3,143	)
Capital expenditures			(58,719	)			(12,500	)
Net cash used in investing activities			(58,719	)			(1,515,643	)
FINANCING ACTIVITIES
Payments on notes payable			(204,713	)			(200,142	)
Retirement of fractional shares			(2,604	)			—
Net cash used in financing activities			(207,317	)			(200,142	)
Decrease in cash and cash equivalents			(390,629	)			(2,848,393	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			1,016,483				3,864,876
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	625,854			$	1,016,483
Non-cash investing and financing activities:
Financing of insurance premiums		$	156,170			$	373,621
Purchase of property and equipment with company stock		$	685,714			$	—
Property and equipment acquired as partial settlement of loan receivable		$	201,000			$	—
Increase in asset retirement obligation and property and equipment		$	391,369			$	—