BLUE DOLPHIN ENERGY CO - Annual Report: 2008 (Form 10-K)

Description

Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

T. Scott Howard Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2008


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

For the transition period from _________ to _________.

Commission File No. 0-15905

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
(713) 568-4725

(Address and telephone number, including area code, of registrant’s principal executive offices)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $.01 per share		Nasdaq Capital Market

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

None

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

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company þ

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

Aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2008 was approximately $24.7 million based on the closing price of $2.12 per share on the NASDAQ Capital Market.


Number of shares of common stock outstanding as of March 10, 2009			11,745,299

Documents Incorporated By Reference

Certain sections of the registrant’s definitive proxy statement for the 2009 Annual Meeting of Stockholders of the registrant (sections entitled “Ownership of Securities of the Company,” “Election of Directors,” “Executive Compensation” and “Transactions With Related Persons”), 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, 2008, 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	18
ITEM 1B.	UNRESOLVED STAFF COMMENTS	23
ITEM 2.	PROPERTIES	23
ITEM 3.	LEGAL PROCEEDINGS	23
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	23

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	24
ITEM 6.	SELECTED FINANCIAL DATA	25
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	33
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	58
ITEM 9A(T).	CONTROLS AND PROCEDURES	58
ITEM 9B.	OTHER INFORMATION	59

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	60
ITEM 11.	EXECUTIVE COMPENSATION	60
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	60
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	60
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	60

PART IV

ITEM 15.	EXHIBITS	61

SIGNATURES		64
EX-21.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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:

	•		the level of utilization of our pipelines;

	•		availability and cost of capital;

	•		actions or inactions of third party operators for properties where we have an interest;

	•		the risks associated with oil and gas exploration;

	•		the level of production from oil and gas properties that we have interests in;

	•		gas and oil price volatility;

	•		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;

	•		regulatory developments; and

	•		general economic conditions.

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 Energy Company, a Delaware corporation formed in 1986, is a holding company and conducts substantially all of its operations through its subsidiaries. We conduct our business activities in two primary business segments: (i) pipeline transportation and related services for producer/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. All of our operations are in the Gulf of Mexico, except our onshore facilities which we own and operate to process and store natural gas and liquids to primarily serve our offshore operations. We have eight employees and two consultants. Our common stock is 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 properties, are defined in the “Glossary of Certain Oil and Gas Terms” of this Form 10-K.

Recent Developments

The Blue Dolphin Pipeline System (“BDPS”) is currently transporting an aggregate of approximately 18 MMcf of gas per day from ten shippers and the GA 350 Pipeline is currently transporting an aggregate of approximately 22 MMcf of gas per day from six shippers. Annual revenues from pipeline operations were $2,448,831 in 2008. Throughput on the Blue Dolphin System and the GA 350 Pipeline increased during 2008 due to increases in production from three shippers that commenced deliveries in the second half of 2007, including delivery of production from one shipper on the Blue Dolphin System and two shippers on the GA 350 Pipeline.

In our oil and gas exploration and production segment, production from the High Island Block 37 A-2 well was restarted in December 2007 after experiencing production problems in April 2007. The well was shut-in for approximately eight months. Production from High Island Block 37 averaged approximately 1.7 MMcf of gas per day in 2008 as compared to approximately 5.4 MMcf of gas per day in 2007. We recognized net oil and gas sales revenues of approximately $246,000 in 2008 associated with our approximate 2.8% working interest in High Island Block 37. The B-1 well experienced production problems in January 2008 and is currently shut-in. The A-2 well resumed production in the first quarter of 2009 after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008. We believe the A-2 well could continue to produce until early 2011, however, the well could deplete faster than currently projected or could develop production problems resulting in the cessation of production.

One well in High Island Block 115 commenced production in late November 2007. We had previously earned a 2.5% working interest in this well, which was drilled successfully in the second quarter 2007. We recognized net oil and gas sales revenues of approximately $294,000 from this well in 2008. The well resumed production in the first quarter of 2009, after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008.

In December 2008, an exploratory well was drilled in Galveston Area Block 321 near our Blue Dolphin Pipeline System. We elected not to participate in this well; however, we maintained a 0.5% overriding royalty interest in the well. In January 2009, it was concluded the well was economically successful and it is expected to be connected to our system in the second quarter of 2009.

Pipeline Operations and Activities

All of our pipeline assets are held in, and operations conducted by, Blue Dolphin Pipe Line Company.

The table below provides more information on our pipeline segments:


Pipeline					Miles of		Capacity		Storage		Average Throughput
Segment	Market	Ownership			Pipeline		(MMcf/d)		(Bbls)⁽¹⁾		(MMcf/d)
											2008		2007		2006
BDPS	Gulf of Mexico		83.3	%		34		160		85,000		22.6		22.3		17.3
GA 350	Gulf of Mexico		83.3	%		13		65		—		23.8		22.6		9.1
Omega⁽²⁾	Gulf of Mexico		83.3	%		18		110		—		—		—		—


(1)		Storage facility connected in Freeport, Texas.

(2)		Inactive.

The economic return on our pipeline system investments and the fees chargeable for the services provided are dependent upon the amounts of gas and condensate gathered and transported. Currently, the level of throughput on our pipeline systems is significantly below maximum capacity. Competition for provision of gathering and transportation services similar to ours is intense in the market areas we serve. See “Competition” for additional information. Since contracts for gathering and transportation services with third party producer/shippers may be for specified time periods, there can be no assurance that current or future producer/shippers will not subsequently tie-in to alternative transportation systems or that current rates charged will be maintained in the future. We actively market our gathering and transportation services to producer/shippers operating in the vicinity of our pipeline systems. Future utilization of the pipelines and related facilities will depend upon the success of drilling programs around the pipelines, and the attraction, and retention, of producer/shippers to the systems.

•		Blue Dolphin Pipeline System — The Blue Dolphin Pipeline System (the “Blue Dolphin System”) includes: the Blue Dolphin Pipeline, an offshore platform, the Buccaneer Pipeline, onshore facilities for condensate and gas separation and dehydration, 85,000 Bbls of above-ground tankage for storage of crude oil and condensate, a barge loading terminal on the Intracoastal Waterway and 360 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the pipeline system’s onshore facilities, pipeline easements and rights-of-way are located. We own an 83% undivided interest in the Blue Dolphin System. The Blue Dolphin System gathers and transports gas and condensate from various offshore fields in the Galveston Area of the Gulf of Mexico to our onshore facilities located in Freeport, Texas. After processing, the gas is transported to an end user and a major intrastate pipeline system with further downstream tie-ins to other intrastate and interstate pipeline systems and end users.

		The Blue Dolphin Pipeline consists of two segments, an offshore segment and an onshore segment. The offshore segment transports both gas and condensate and is comprised of approximately 34 miles of 20-inch pipeline originating at an offshore platform in Galveston Area Block 288 and running to shore. The offshore segment also includes the platform in Galveston Area Block 288 and 5 field gathering lines totaling approximately 27 miles connected to the main 20-inch line. An additional 2 miles of 20-inch pipeline onshore connects the offshore segment to the onshore facility at Freeport, Texas. The onshore segment also includes approximately 2 miles of 16-inch pipeline for transportation of gas from the onshore facility to a sales point at a chemical plant complex and intrastate pipeline system tie-in in Freeport, Texas. The Buccaneer Pipeline, an approximate 2 mile, 8-inch liquids pipeline, transports condensate from the onshore facility storage tanks to our barge-loading terminal on the Intracoastal Waterway near Freeport, Texas for sale to third parties.

Various fees are charged to producer/shippers for provision of transportation and onshore facility services. The Blue Dolphin Pipeline has an aggregate capacity of approximately 160 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. Unless otherwise stated, all gas and liquids volumes transported are attributable to production from third party producer/shippers.

•

Galveston Area Block 350 Pipeline — We own an 83% undivided interest in the 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. Unless otherwise stated, all gas and liquids volumes transported are attributable to production from third party producer/shippers.

•

Other — We also own an 83% undivided interest in a third offshore pipeline, the Omega Pipeline, which is currently inactive. 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. Reactivation of the Omega Pipeline will be dependent upon future drilling activity in the vicinity and successfully attracting producer/shippers to the system.

Oil and Gas Exploration and Production Activities

Although we sold substantially all of our producing oil and gas properties in 2002, we continue our oil and gas exploration and production activities, which include the exploration, acquisition, development, operation and, when appropriate, disposition of oil and gas properties. We focus our oil and gas activities in the western Gulf of Mexico off the Texas coast. We currently own seismic and other data that may be used to evaluate and develop prospects, including a non-exclusive license to approximately 200 blocks of 3-D seismic data covering 1,152,000 acres in the western Gulf of Mexico and a substantial inventory of close grid 2-D seismic data. Our oil and gas assets are held by Blue Dolphin Petroleum Company.

The leasehold interests we hold in properties are subject to royalty, overriding royalty and interests of others.

Oil and Gas Exploration and Production Assets and Activities. Following is a description of our oil and gas exploration and production assets and activities:

•

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. In December 2008, drilling of an exploratory well in Galveston Area Block 321 was commenced near our Blue Dolphin Pipeline System. We elected not to participate in this well. However, we maintained a 0.5% overriding royalty interest in the well. In January 2009, it was concluded that the well was successful and will be connected to our Blue Dolphin Pipeline System in second quarter 2009.

•

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. We own a 2.5% working interest in a single production zone in one well in this block. Production commenced in late November 2007. The well is currently producing. However, it was down for over four months due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008.

•

High Island Block 37 — High Island Block 37 is located approximately 15 miles south of Sabine Pass, offshore Texas, in an average water depth of approximately 36 feet. We own an approximate 2.8% working interest in this lease that covers 5,760 acres. The lease is operated by Seneca Resources Corporation and contains two wells. The A-2 well resumed production in the first quarter of 2009 after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in

September 2008. In early 2008, we elected to participate in an exploratory well for a 2.8% working interest. Drilling of the exploratory B-2 well commenced in mid-April 2008. The B-2 well was determined to be non-commercial and was plugged and abandoned in the third quarter of 2008.

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

Proved Oil and Gas Reserves. We have prepared estimates of proved reserves, and discounted present value of future net revenues to our net interest as of December 31, 2008.

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 revenues attributable thereto.

Estimates of production and future net revenues cannot be expected to represent accurately the actual production or revenues 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 “Item 8 — Notes to Consolidated Financial Statements” for further information concerning our proved reserves, changes in proved reserves, estimated future net revenues and costs incurred in our oil and gas activities and the discounted present value of estimated future net revenues from our proved reserves.

The following table presents the estimates of proved reserves, proved developed reserves (as hereinafter defined) and the discounted present value of future net revenues or expenses from proved reserves after income taxes (in thousands) to our net interest in oil and gas properties as of December 31, 2008. The discounted present value of future net revenues 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.

Remainder of Page Intentionally Left Blank

Proved Reserves
As of December 31, 2008^{(1) (2)}


					Present Value
					of Future Net
	Net Oil		Net Gas		Cash Inflows
	Reserves		Reserves		(Outflows) ⁽¹⁾
	(Mbbls)		(MMcf)		(in thousands)
Proved Reserves
Galveston Area Block 321		0.3		14		81
High Island Block 115		0.4		129		383
High Island Block 37		0.1		15		46

Total Proved Reserves		0.8		158	$	510


Proved Developed
Galveston Area Block 321		0.3		14		81
High Island Block 115		0.4		129		383
High Island Block 37		0.1		15		46

Total Proved Developed		0.8		158	$	510


(1)		The estimated present value of future net cash outflows from our proved reserves has been determined by using prices of $44.60 per barrel of oil and $5.26 per Mcf of gas, representing the December 31, 2008 prices for oil and gas and discounted at a 10% annual rate in accordance with requirements for reporting oil and gas reserves pursuant to regulations promulgated by the Securities and Exchange Commission (the “SEC Method”).

(2)		As of December 31, 2008, we reported no proved undeveloped reserves.

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 (in thousands).

Estimated Undiscounted Capital Expenditures
Associated with Plugging and Abandonment of Wells


	Years Ending December 31,
	2009		2010		2011		2012		2013

Galveston Area Block 321		—		—		—		—		—
High Island Block A-7		—		265		—		—		—
High Island Block 37		—		73		—		—		—
High Island Block 115		—		—		39		—		—

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

Net Production, Price and Cost Data


	Years Ended December 31,
	2008		2007		2006
Gas:
Production (Mcf)		44,700		72,788		312,146
Revenue	$	526,522	$	476,224	$	2,131,415
Average production per day (Mcf)^(*)		122.5		199.4		772.3
Average sales price per Mcf	$	11.78	$	6.54	$	6.83
Condensate:
Production (Bbls)		117		177		1,823
Revenue	$	14,057	$	10,345	$	114,114
Average production per day (Bbls)^(*)		0.3		0.5		5.0
Average sales price per Bbl	$	120.25	$	58.45	$	62.60
NGLs:
Production (gallons)		—		36,372		137,139
Revenue	$	—	$	30,842	$	113,285
Average production per day (gallons)^(*)		—		99.7		375.7
Average sales price per gallon	$	—	$	0.85	$	0.83

Production costs ^(**):
Per Mcfe:	$	5.36	$	3.04	$	1.34


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

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

2008 Drilling Activity. In early 2008, we elected to participate in an exploratory well for a 2.8% working interest. Drilling of the exploratory B-2 well commenced in mid-April 2008. The B-2 well was determined to be non-commercial and was plugged and abandoned in the third quarter of 2008.


	Net Exploratory⁽¹⁾
	2008		2007
Wells Drilled
Gulf of Mexico Productive		—		—
Dry		1		—

		1		—


(1)		Gross interest reflects the total wells we participated in, regardless of our ownership interest.

Customers

We generated revenues from both of our business segments. Arena Offshore, W&T Offshore, Gryphon Exploration Co., and Apex Oil & Gas accounted for approximately 17%, 16%, 12%, and 11%, respectively, of our revenues in 2008. Revenues from customers exceeding 10% of revenues were as follows for 2008 and 2007:


	Oil and Gas		Pipeline
	Sales		Operations		Total
Year Ended December 31, 2008:
Arena Offshore	$	—	$	513,634	$	513,634
W&T Offshore	$	—	$	488,083	$	488,083
Gryphon Exploration Co.	$	—	$	367,153	$	367,153
Apex Oil & Gas	$	—	$	338,836	$	338,836

Year Ended December 31, 2007:
Apex Oil & Gas	$	—	$	809,420	$	809,420
W&T Offshore	$	—	$	519,866	$	519,866
Gryphon Exploration Co.	$	—	$	341,406	$	341,406

Markets & Competition

The availability of a ready market for oil and natural gas, and the prices of oil and natural gas, depends upon a number of factors which are beyond our control. These include, among other things:

	•		the level of domestic 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 affecting the supply and demand for crude oil, condensate, natural gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the oil and natural gas produced for sale or prices chargeable for transportation and storage services, which we provide. Our sale of natural gas is generally made at the market prices at the time of sale. Therefore, even though we sell natural gas to major purchasers, we believe other purchasers would be willing to buy our natural gas at comparable market prices.

Vigorous competition occurs among oil, gas and other energy sources, and between producers, transporters, and distributors of oil and gas. Our pipeline business faces competition from other pipelines in the markets that we serve. The principal elements of competition among pipelines are rates, terms of service, access to markets, flexibility and reliability of service. Our oil and natural gas business competes 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 these competitors are large, well-established companies that have financial and other resources that are substantially greater than ours, which give them an

advantage over us in evaluating and obtaining properties and prospects. Our ability to acquire additional pipelines and oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. There is also competition for the hiring of experienced personnel to manage and operate our assets. Several highly competitive alternative transportation and delivery options exist for current and potential customers of our traditional gas and oil gathering and transportation business. Competition also exists with other industries in supplying the energy and fuel needs of consumers.

Governmental Regulation

The production, processing, marketing, and transportation of oil and gas by us are subject to federal, state and local regulations which can have a significant impact upon our overall operations.

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 Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting producer sales of gas, effective January 1, 1993. The Energy Policy Act of 2005 did not alter our non-FERC-jurisdictional status, but has greatly expanded FERC’s authority, including enforcement authority against market manipulation “in connection with” FERC-jurisdictional transactions. FERC has undertaken vigorous enforcement actions against a number of entities, including those not subject to direct FERC regulation, and, 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. Thus Congress could reenact regulatory controls in the future. The rates, terms and conditions applicable to interstate transportation of gas by pipelines are regulated by the FERC under the NGA, as well as under Section 311 of the NGPA. In February 2007, FERC issued a policy order acknowledging its lack of jurisdiction over offshore gathering, but stating that FERC would intervene in the event that interstate pipelines with affiliated offshore gathering lines engage in anticompetitive behavior, such 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”). The 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 the 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 the 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.

Safety and Operational Regulations. Our operations are generally subject to safety and operational regulations administered primarily by the United States Minerals Management Service (“MMS”), the U.S. Department of Transportation, the U.S. Coast Guard, the FERC and/or various state agencies. In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to leases 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. All of our exploration and production operations are currently located on federal oil and gas leases in the OCS, which are administered by the MMS. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA that are subject to interpretation and change by the MMS. For offshore operations, lessees must obtain MMS 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, lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS 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, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurance that such obligations will be met. The cost of these 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 the MMS. Under some circumstances, the MMS 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 conducted on offshore federal leases, liability may generally be imposed under OCSLA for costs of clean-up and damages caused by pollution resulting from such operations, other than 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, the MMS may also require any of our operations on federal leases to be suspended or terminated in the affected area. Furthermore, the MMS generally requires that offshore facilities be dismantled and removed within one year after production ceases or the lease expires.

Environmental Regulation. Our activities with respect to (1) exploration, development and production of oil and natural gas and (2) the operation and construction of pipelines, plants, and other facilities for the transportation and processing, and storage of oil and natural gas are subject to stringent environmental regulation by local, state and federal authorities, including the U.S. Environmental Protection Agency (“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 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. It is not anticipated that, in response to such regulation, we will be required in the near future 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 responsible parties with respect to 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 or arranged for the disposal of a hazardous substance at the site, 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. At this time, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA.

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 for offshore facilities of all removal costs plus $75 million, and 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 cleanup, liability limits likewise 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 type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges, worst-case spill potential and other factors. We believe we have established adequate financial responsibility. While the financial responsibility requirements under OPA may be amended to impose additional costs on us, the impact of such a change is not expected 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 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 of America 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 on 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 (“CCA”) establishes the Texas Coastal Management Program that applies in the nineteen Texas counties that border the Gulf of Mexico and its tidal bays. The CCA 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 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 this statutory $35 million coverage.

Federal and state legislative rules and regulations are pending that, if enacted, could significantly affect the oil and gas industry. It is impossible to predict which of those federal and state proposals and rules, if any, will be adopted and what effect, if any, they would have on our operations.

In addition, 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, expenses and costs. The trend in such regulation 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. It is not anticipated that, in response to such regulation, we will be required in the near future to expend amounts that are material relative to our total capital structure. However, it is possible that the costs of compliance with environmental and health and safety laws and regulations will continue to increase. Given the frequent changes made to environmental and health and safety regulations and laws, we are unable to predict the ultimate cost of compliance.

Employees

We have a total of eight employees and two consultants. Our employees supervise and coordinate the operation and administration of our oil and gas properties, pipelines and other assets. From time to time, major maintenance, engineering and construction projects are contracted to third-party engineering and service companies.

Environmental

A description of our environmental activities is included in Part II, Item 8 Financial Statement & Supplementary Data.

Executive Officers of the Registrant

Our executive officers as of March 12, 2009 are listed below:


		Officer
Name	Office	Since	Age
Ivar Siem	Chairman of the Board and Chief Executive Officer	1989	62
Michael J. Jacobson	President	1990	62
Thomas W. Heath	Executive Vice President and Secretary	2007	46
T. Scott Howard	Accounting Manager, Treasurer and Assistant Secretary	2006	37

Ivar Siem has served as Chairman of the Board of Directors of the Company since 1989 and was appointed as Chief Executive Officer in 2004. Since 2000 he has also served as Chairman of the Board of Directors and President of Drillmar, Inc., a well construction and intervention company. From 1995 to 2000 Mr. Siem served on the Board of Directors of Grey Wolf, Inc., during which time he served as Chairman from 1995 to 1998 and as interim President in 1995 during its restructuring. Since 1981, he has been an international consultant in energy, technology and finance. From 1974 to 1981, Mr. Siem managed the oil and gas interests of Fred. Olsen and from 1977 he managed their drilling operation, Dolphin International, Inc. 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.

Michael J. Jacobson has served as President of the Company since 1990 having also served in dual capacities as Chief Executive Officer from 1990 to 2004 and as Secretary from 2005 to 2006 and again in 2008. Mr. Jacobson also served as Treasurer in 2008. Prior to joining the Company, Mr. Jacobson served in various senior management positions in the energy industry, including Senior Vice President and Chief Financial and Administrative Officer for Creole International, Inc. and its subsidiaries, international providers of engineering and technical services to the energy sector, Vice President of Operations for the parent holding company, and Vice President and Chief Financial Officer of Volvo Petroleum, Inc. and certain Fred. Olsen oil and gas interests. Mr. Jacobson began his career with Shell Oil Company in 1968, where he served in various analytical and management capacities in the exploration and production organization until 1974. Mr. Jacobson received his Bachelor of Science in Finance from the University of Colorado.

Thomas W. Heath was appointed as Executive Vice President of the Company in 2007. From 2004 to 2007 he served as a Vice President of Union Bank of California, N.A., an affiliate of Bank of Tokyo-Mitsubishi UFJ, Ltd., where he developed and implemented an energy derivatives desk supporting Energy Capital Services. From 1988 to 2004 Mr. Heath held a variety of management and executive level positions with the evolving marketing units of Acadian Gas Pipeline System, Coral Energy, L.P. (formerly Shell Trading Gas & Power), Sempra Energy Trading Corp. and Tejas Gas Corporation. Mr. Heath began his career in 1983 with Columbia Gulf Transmission Company where he served in various operational and commercial positions until 1988. He is an alumnus of the University of Houston.

T. Scott Howard was appointed as Treasurer in February 2009 and Assistant Secretary of the Company in April 2008. He has served as Accounting Manager of the Company since 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 in 1994 as a Staff Accountant for Griffin, Iles, Masel & Duval, LLP, a public accounting firm, until 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

Our website is http://www.blue-dolphin.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the SEC. Information about each of our Board members, 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

Risks Related to our Business

Oil and gas prices are volatile and a substantial and extended decline in the price of oil and gas would have a material adverse effect on us.

The tightening of natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, and this volatility in natural gas prices is expected to continue. Our revenues, profitability, operating cash flow and our 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:

	•		weather conditions in the United States;

	•		the condition of the United States economy;

	•		the actions of the Organization of Petroleum Exporting Countries;

	•		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

	•		generally impairing our ability to obtain needed capital.

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

As a result of our sale of substantially all of our proved oil and gas reserves in 2002 and the limited amount of reserves on properties we currently own interests in, we expect that our future revenues will be primarily dependent on the level of use of our pipeline systems. Revenues from oil and gas sales accounted for approximately 18% of our total revenues in 2008 as compared to 17% in 2007, a variance of approximately $23,000. Various factors can influence the level of use of our pipeline systems, 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 to attract new producer/shippers to our pipeline systems. 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. Our working interests are in properties in the Gulf of Mexico where, generally, the rate of production declines more rapidly than in many other producing areas of the world. As the level of production from these properties continues to decline, our revenue from oil and gas sales will decrease. Unless we are able to replace production revenue with revenue from interests in other oil and gas properties, increase the level of utilization of our pipelines or acquire other revenue generating assets at an acceptable cost, our revenues and cash flow from operations will decrease and our financial condition will be materially adversely affected.

A significant decrease in exploration and production activity in areas where our pipelines are, the decline in production from existing wells, depressed commodity prices or otherwise, would adversely affect our revenues and cash flow.

The profitability of our pipeline operations is materially impacted by the volume of throughput. A material decrease in production in our areas of operation would result in a further decline in our throughput volumes. We have no control over many factors affecting production activity, including prevailing and projected commodity prices, demand for oil and gas, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. The level of throughput on our pipelines is significantly below maximum capacity. Failure to connect new wells to our pipelines would result in the amount of throughput being reduced further over time. Our ability to connect to new wells will be dependent on the level of drilling activity in our areas of operations and competitive market factors. The effect of any decrease in the throughput handled by our pipelines would reduce our revenues and operating income.

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

All of our assets are located in the Western Gulf of Mexico and the onshore Gulf Coast of Texas. Because our assets are not as diversified geographically as many of our competitors, our business is subject to local conditions more than other, more geographically diversified companies. Any regional event, including price fluctuations, natural disasters and restrictive regulations that increase costs may adversely impact our business more than if our assets were geographically diversified.

If we are not able to generate sufficient funds from our operations and other financing sources, we may not be able to finance our operations.

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

Low commodity prices, production problems, declines in production, disappointing drilling results and other factors beyond our control could further reduce our funds from operations. As a result we may have to seek debt and equity financing to meet our working capital requirements. Furthermore, we incurred a loss of approximately $2.0 million in 2008 and approximately $1.6 million in 2007. These losses may affect our ability to obtain financing. In addition, financing at acceptable terms may or may not be available to us in the future. In the event additional capital is not available, we may be forced to sell some of our assets at unfavorable terms or on an untimely basis.

The global financial crisis may have impacts 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 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 revenues.

We face strong competition from larger companies that may negatively affect our ability to carry on operations.

We operate in a highly competitive industry. Our competitors include major integrated oil companies, substantial 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:

	•		most of our competitors have greater financial resources than we do, which gives them better access to capital to acquire assets; and

	•		we sometimes establish a higher standard for the minimum projected rate of return on invested capital than some of our competitors since we cannot afford to absorb certain risks. We believe this puts us at a competitive disadvantage in acquiring pipelines and 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 Securities and Exchange Commission (“SEC”) regarding 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 prices and costs in effect at December 31, 2008. 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, other companies operate or control the development of the oil and gas properties in which we have an interest. As a result, we depend on the operator of the wells or leases to properly conduct lease acquisition, drilling, completion and production operations. The failure of an operator, or the drilling contractors and other service providers selected by the operator to properly perform services, or an operator’s failure to act in ways that are in our best interest, could adversely affect us, including the amount and timing of revenues, if any, we receive from 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, for example, 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 to pursue, acquisitions. Our business may be adversely affected if we cannot effectively integrate acquired operations.

One of our business strategies has been to acquire operations and assets that are complementary to our existing businesses. Acquiring operations and assets involves financial, operational and legal risks. These risks include:

	•		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 to pay and reduce our acquisition opportunities. We are often out-bid by larger, better capitalized companies for acquisition opportunities 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 those operations, such as:

	•		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 peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more extensive 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 over 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 as well as re-drilling expenses and pollution coverage for wells out of control.

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 that is not fully insured or indemnified against occurs, it could materially and adversely affect our financial condition and results of operations.

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.

Our gathering systems and exploration and production businesses require the retention and recruitment of a skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

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, but 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 OPA 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 OPA, could have a material adverse impact on us.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information appearing in Item 1 describing our oil and gas properties, pipelines and other assets under the caption “Description of Business” 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 $107,000.

ITEM 3. LEGAL PROCEEDINGS

We are a party to litigation that is incidental to our business and neither we nor any of our property is subject to any material pending legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Remainder of Page Intentionally Left Blank

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 10, 2009, there were approximately 500 stockholders of record which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank. NASDAQ quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.

The following table sets forth, for the periods indicated, the high and low closing bid prices for our common stock as reported by NASDAQ.


Quarter Ended	High		Low

2008
December 31, 2008	$	0.84	$	0.33
September 30, 2008	$	2.09	$	0.83
June 30, 2008	$	2.39	$	1.25
March 31, 2008	$	1.94	$	1.23

2007
December 31, 2007	$	3.15	$	1.21
September 30, 2007	$	3.80	$	2.92
June 30, 2007	$	4.01	$	2.97
March 31, 2007	$	4.33	$	2.81

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 our Board of Directors 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.

Remainder of Page Intentionally Left Blank

ITEM 6. SELECTED FINANCIAL DATA

Financial information by quarter is summarized below:


	Quarters Ended
	March 31			June 30			September 30			December 31			Total
2008
Revenue from operations:
Pipeline operations	$	547,817		$	695,402		$	561,171		$	644,441		$	2,448,831
Oil and gas sales		130,720			293,553			120,108			(3,802	)		540,579

Total Revenue from operations		678,537			988,955			681,279			640,639			2,989,410

Cost of operations:
Pipeline operating expenses		415,956			402,096			415,581			489,009			1,722,642
Lease operating expenses		50,173			83,094			40,710			69,473			243,450
Depletion, depreciation and amortization		131,338			117,690			164,689			114,255			527,972
Impairment of oil and gas properties		—			—			—			213,563			213,563
General and administrative expenses		561,625			489,364			426,342			476,165			1,953,496
Stock Based compensation		72,184			72,184			75,222			78,685			298,275
Accretion expense		28,576			26,733			26,356			26,355			108,020

Total cost of operations		1,259,852			1,191,161			1,148,900			1,467,505			5,067,418

Other income (expense), including income tax expense		55,941			26,727			24,884			4,216			111,768


Net income (loss)		(525,374	)		(175,479	)		(442,737	)		(822,650	)		(1,966,240	)


Income (loss) per share:
Basic and diluted	$	(0.05	)	$	(0.02	)	$	(0.04	)	$	(0.07	)	$	(0.17	)

2007
Revenue from operations:
Pipeline operations	$	559,813			531,762			717,118			685,713			2,494,406
Oil and gas sales		295,183			89,165			68,470			64,593			517,411

Total Revenue from operations		854,996			620,927			785,588			750,306			3,011,817

Cost of operations:
Pipeline operating expenses		516,171			562,692			349,293			360,132			1,788,288
Lease operating expenses		67,318			90,464			91,202			(8,667	)		240,317
Depletion, depreciation and amortization		137,176			152,203			134,041			131,284			554,704
General and administrative expenses		483,362			623,390			439,877			449,795			1,996,424
Stock Based compensation		—			13,440			40,320			128,092			181,852
Accretion expense		30,391			30,391			30,392			29,210			120,384

Total cost of operations		1,234,418			1,472,580			1,085,125			1,089,846			4,881,969

Other income (expense), including income tax expense		60,234			67,168			61,389			55,789			244,580


Net income (loss)		(319,188	)		(784,485	)		(238,148	)		(283,751	)		(1,625,572	)


Income (loss) per share:
Basic and diluted	$	(0.03	)	$	(0.07	)	$	(0.02	)	$	(0.02	)	$	(0.14	)

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 — Description of Business” and “Item 8 — 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 assets are located offshore and onshore in the Texas Gulf Coast area. Our goal is to create greater long-term value for our stockholders by increasing the utilization of our existing pipeline assets and acquiring additional strategic assets that diversify our asset base, improve our competitive position and are accretive to earnings. Although we are primarily focused on acquisitions of pipeline assets and maximizing our current facilities, we also continue to review, evaluate opportunities and acquire additional oil and gas properties.

Pipeline Transportation. Despite an increase in revenues from our pipeline operations in 2007 as a result of commencement of deliveries of production from shippers on both the Blue Dolphin Pipeline System and the GA 350 Pipeline, we experienced a decline in revenues from our pipeline operations in 2008. The decline in revenues resulted from no additional shippers into either the Blue Dolphin Pipeline System or the GA 350 Pipeline, as well as a temporary shut down of operations on both pipelines immediately preceding and following Hurricane Ike in September 2008. A successful well was drilled in Galveston Area Block 321 in the latter part of 2008. We have had discussions with the operator and expect that the well will connect to the Blue Dolphin Pipeline System in the second quarter of 2009. The Blue Dolphin System is currently transporting an aggregate of approximately 18 MMcf of gas per day from ten shippers. The GA 350 Pipeline is currently transporting an aggregate of approximately 22 MMcf of gas per day from six shippers.

Oil and Gas Exploration and Production.

•		Galveston Area Block 321 — In September 2008, although we elected not to participate in an exploratory well in Galveston Area Block 321, we maintained a 0.5% overriding royalty interest in the exploratory well. Drilling of the well commenced in late December 2008 and continued through early January 2009. The well was successfully completed and we expect production to commence in the second quarter of 2009. Production will be delivered through the Blue Dolphin Pipe Line System.

•		High Island Block 115 — During 2007, a well in High Island Block 115 that had previously earned us a 2.5% working interest was re-entered and sidetracked successfully. Production from the well commenced in late November 2007. The well resumed production in the first quarter of 2009 after being shut-in, due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008.

•		High Island Block 37 — The A-2 well resumed production in the first quarter of 2009 after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008. In early 2008, we elected to participate in an exploratory well in High Island Block 37 at our 2.8% working interest. Drilling of the exploratory B-2 well commenced in mid-April 2008. The B-2 well was determined to be non-commercial and was plugged and abandoned in the third quarter of 2008.

Our pipeline assets remain significantly under-utilized. The Blue Dolphin System is currently operating at approximately 11% of capacity, the GA 350 Pipeline is currently operating at approximately 34% of capacity and the Omega Pipeline is inactive. Production declines, temporary stoppages or cessations of production from wells tied into our pipelines or from our working and overriding royalty interests in wells in Galveston Area and High Island blocks as noted above could have a material adverse effect on our cash flows and liquidity if the resulting revenue declines are not offset by revenues 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, 2008 (“current period”), we reported a net loss of $1,966,240, compared to a net loss of $1,625,572 for the year ended December 31, 2007 (“previous period”). For the three months ended December 31, 2008 (the “current quarter”), we reported a net loss of $822,650 compared to a net loss of $283,751 for the three months ended December 31, 2007 (the “previous quarter”).

2008 Compared to 2007

Revenue from Pipeline Operations. Revenues from pipeline operations decreased by $45,575, or 2%, in the current period to $2,448,831. Revenues in the current period from the Blue Dolphin System totaled approximately $2,042,000 compared to approximately $2,107,000 in the previous period. Daily gas volumes transported through the Blue Dolphin System averaged approximately 23 MMcf of gas per day in the current period compared to approximately 22 MMcf of gas per day in the previous period. Revenues on the GA 350 Pipeline increased by approximately $20,000 to approximately $407,000 in the current period primarily due to throughput from new shippers that commenced production in the previous period. Average daily gas volumes for GA 350 transported increased to approximately 24 MMcf of gas per day in the current period from approximately 23 MMcf of gas per day in the previous period.

Revenue from Oil and Gas Sales. Revenues from oil and gas sales increased by $23,168, or 4.5%, to $540,579 in the current period primarily due to increased commodity prices. One well in High Island Block 37 went off production in January 2008 and production has not been re-established. The other well in High Island Block 37 produced for a portion of the current period. These decreases in production were offset by production in the current period from High Island Block 115, which commenced production in late November of the previous period.

Revenues were also affected by an increase in the realized price of natural gas. Our average realized gas price per Mcf in the current period was $11.78 compared to $6.54 in the previous period. The sales mix by product was 97% gas and 3% condensate. Our average realized price per barrel of condensate was $120.25 in the current period compared to $58.45 in the previous period. Revenue breakdown for the current period by field was approximately $246,000 for High Island Block 37 and $294,000 for High Island Block 115.

Pipeline Operating Expenses. Pipeline operating expenses decreased by $65,646 to $1,722,642 in the current period. The decrease was primarily due to decreases in pipeline repair of approximately $176,000, legal fees of approximately $109,000 and compressor repair expenses of approximately $113,000. The decreases were partially offset by increases in storage tank repairs of approximately $214,000, property insurance of approximately $82,000 and bad debt expense of approximately $27,000.

Lease Operating Expenses. Lease operating expenses increased $3,133, or 1% in the current period to $243,450.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $26,732 in the current period to $527,972 primarily due to interruption of production in the fourth quarter from damage to third party shore facilities during Hurricane Ike.

Impairment of Oil and Gas Properties. We recorded a full cost ceiling impairment of $213,563 for the year ended December 31, 2008. A variety of economic and other factors have recently caused significant declines in oil and gas prices. We utilize 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 was calculated using prices of $44.60 per barrel of oil and $5.26 per MMbtu. Accordingly, at December 31, 2008, our costs exceeded our ceiling limitation, resulting in a write-down of our oil and natural gas properties.

General and Administrative Expenses, and Stock Based Compensation. General and administrative expenses increased $73,495 in the current period to $2,251,771 primarily due to increased compensation related expenses of approximately $136,000, including $116,000 of non-cash stock option expense. These increases were partially offset by decreases in legal fees of approximately $33,000 and other accounting and tax expense of approximately $39,000.

Interest and Other Income. Interest and other income decreased $128,568 in the current period due to a decrease in invested funds and the interest rate earned on those funds.

Three Months Ended December 31, 2008 Compared to Three Months Ended December 31, 2007

Revenue from Pipeline Operations. Revenues from pipeline operations decreased by $41,272, or 6%, in the current quarter to $644,441. Revenues in the current quarter from the Blue Dolphin System decreased to approximately $548,000 compared to approximately $559,000 in the previous quarter. Although daily gas volumes transported on the Blue Dolphin System averaged 25 MMcf of gas per day in the current quarter, up from 22 MMcf of gas per day in the previous quarter, lower condensate prices in the current quarter reduced our separation and storage revenue to offset the increase in gas transportation revenue. Revenues on the GA 350 Pipeline decreased to approximately $97,000 compared to approximately $127,000 in the previous quarter due to a decrease in average daily gas volumes transported of 22 MMcf of gas per day in the current quarter from 29 MMcf of gas per day in the previous quarter.

Revenue from Oil and Gas Sales. Revenues from oil and gas sales decreased by $68,395, or 106%, in the current quarter primarily due to the interruption in production from High Island Block 115 and High Island Block 37 from damage to third party shore facilities caused by Hurricane Ike in September 2008.

Pipeline Operating Expenses. Pipeline operating expenses in the current quarter increased by $128,877 to $489,009 due to increases in storage tank repairs and other repairs related to damage from Hurricane Ike.

Lease Operating Expenses. Lease operating expenses increased in the current quarter to $69,473 due to an adjustment of expense in the previous period due to incorrect charges on a producing property.

General and Administrative Expenses and Stock Based Compensation. General and administrative expenses decreased by $23,027 to $554,850 in the current quarter primarily due to a decrease in stock option expense of approximately $39,000 from the previous quarter. This decrease is partially offset by an increase of approximately $11,000 in other accounting expenses associated with Sarbanes-Oxley compliance work.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization decreased in the current quarter by $17,029 to $114,255 due to the interruption in production from High Island Block 115 and High Island Block 37 from damage to third party shore facilities caused by Hurricane Ike in September 2008.

Other Income. Other income decreased due to a decrease in interest income of $47,329 in the current quarter. Interest income decreased because of decreases in both the amount of available funds and the interest rate earned on those funds.

Liquidity and Capital Resources

Sources and Uses of Cash. Our primary source of cash is cash flow from operations. During 2008, we had negative cash flow from operations of approximate $0.6 million, excluding working capital changes, mainly due to low utilization of our pipeline systems and loss of production attributable to Hurricane Ike. We utilized available cash to participate in an exploratory well in High Island Block 37 for a 2.8% working interest for a total of $0.7 million. Unfortunately, the well was determined to be non-commercial and was plugged and abandoned in the third quarter of 2008.

Our Company does 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 of the Company. Our current available cash is $3.9 million at December 31, 2008.


	For Year Ended December 31,
	(in millions)
	2008			2007
Cash Flow from Operations
Loss from operations		($0.7	)		($0.7	)
Change in current assets and liabilities		0.1			0.5

Total cash flow from operations		($0.6	)		($0.2	)

Cash Outflows
Capital expenditures		($0.8	)		($0.1	)

Total cash outflows		($0.8	)		($0.1	)

Total change in cash flows		($1.4	)		($0.3	)

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

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 accountants 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 of December 31, 2008 and the accounting for future asset retirement costs.

Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with Statement of Financial Accounting Standard (“SFAS”) No. 144, 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 under utilized and such underutilization is an indicator of possible impairment at December 31, 2008. Accordingly, we developed future cash flows as of December 31, 2008 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 increasing current leasing and drilling activities, and prospective drilling activity surrounding our pipelines. 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 has been recorded as of December 31, 2008.

The accounting for future abandonment costs changed on January 1, 2003 with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. This standard 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 and relocate or dispose of our offshore platforms, pipeline systems and related onshore facilities, plugging and abandonment of wells and restoration costs of land and seabed. We develop estimates of these costs for each of our assets based upon regulatory requirements, the type of platform structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future abandonment costs on a quarterly basis.

Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109. We adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes (“SFAS 109”). FIN 48 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 new FASB 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 FIN 48 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 FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year.

The provisions of FIN 48 have been applied to all of our material tax positions taken from January 1, 2007 through the fiscal year ended December 31, 2008. 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 FIN 48. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the new pronouncement.

Fair Value Measurements. On January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”), 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, the Financial Accounting Standards Board (“FASB”) issued Staff Position 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), that deferred the effective date of SFAS 157 for one year for nonfinancial assets and liabilities recorded at fair value on a non-recurring basis. The effect of adoption of SFAS 157 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. We are assessing the impact of SFAS 157 for nonfinancial assets and liabilities.

Fair Value Option for Financial Assets and Financial Liabilities. On January 1, 2008, we adopted SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115 (“SFAS 159”). SFAS 159 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 SFAS 159 for any of our financial assets or liabilities upon adoption.

Recently Issued Accounting Pronouncements and Accounting Developments

Business Combinations. In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”), which replaces SFAS No. 141, Business Combinations. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. SFAS 141R will be applicable prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period

beginning on or after December 15, 2008. SFAS 141R would have an impact on accounting for any businesses acquired after the effective date of this pronouncement.

Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51. In December 2007, the FASB also issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51 (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (previously referred to as minority interests). SFAS 160 also requires that a retained non-controlling interest upon the deconsolidation of a subsidiary be initially measured at its fair value. Upon adoption of SFAS 160, we would be required to report any non-controlling interests as a separate component of stockholders’ equity. We would also be required to present any net income allocable to non-controlling interests and net income attributable to the stockholders of the Company separately in our consolidated statements of income. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. SFAS 160 would have an impact on the presentation and disclosure of the non-controlling interests of any non wholly-owned businesses acquired in the future.

Hierarchy of Generally Accepted Accounting Principles. In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. The FASB believes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This statement became effective on November 15, 2008 following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 did not have a material effect on the Company’s results of operations, financial position or cash flows.

Revisions to the SEC’s Oil and Gas Reporting Disclosure Requirements. On December 31, 2008, the SEC issued the Final Rule, which adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the Final Rule is prohibited. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the SEC’s Final Rule include, but are not limited to:

•

Oil and gas reserves must be reported using the average price over the prior 12 month period, rather than year-end prices;

•

Companies will be allowed to report, on an optional basis, probable and possible reserves;

•

Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of “oil and gas producing activities”

•

Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

•

Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs;

•

Companies will be required to report the qualifications and measures taken to assure the independence

and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.

The Company is currently evaluating the potential impact of adopting the Final Rule. The SEC is discussing the Final Rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will begin complying with the disclosure requirements in its annual report on Form 10-K for the year ended December 31, 2009.

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			34
Consolidated Balance Sheets at December 31, 2008 and 2007			35
Consolidated Statements of Operations Years Ended December 31, 2008 and 2007			36
Consolidated Statements of Stockholders’ Equity Years Ended December 31, 2008 and 2007			37
Consolidated Statements of Cash Flows Years Ended December 31, 2008 and 2007			38
Notes to Consolidated Financial Statements			39

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, 2008 and 2007, 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, 2008. 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 (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP
Houston, Texas
March 12, 2009

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets


	December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	3,864,876		$	5,226,779
Accounts receivable, net of allowance for doubtful accounts		442,715			693,977
Prepaid expenses and other current assets		436,242			508,517

Total current assets		4,743,833			6,429,273

Property and equipment, at cost:
Oil and gas properties (full-cost method)		1,286,700			751,175
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		290,313			279,468

		9,016,376			8,470,006
Less: Accumulated depletion, depreciation and amortization		4,494,059			3,966,087

Total property and equipment, net		4,522,317			4,503,919

Other assets		9,463			10,640


Total assets	$	9,275,613		$	10,943,832


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	389,268		$	432,974
Accrued expenses and other liabilities		9,593			109,628
Asset retirement obligations — current portion		—			262,187
Other long-term liabilities — current portion		25,996			25,996

Total current liabilities		424,857			830,785

Long-term liabilities:
Asset retirement obligations, net of current portion		2,183,190			1,831,520
Other long-term liabilities, net of current portion		25,996			51,992

Total long-term liabilities		2,209,186			1,883,512


Total liabilities		2,634,043			2,714,297

Commitments and contingencies

Stockholders’ equity:
Common stock ($.01 par value, 25,000,000 shares authorized, 11,691,243 and 11,610,363 shares issued and outstanding at December 31, 2008 and 2007, respectively)		116,912			116,104
Additional paid-in capital		32,495,417			32,117,950
Accumulated deficit		(25,970,759	)		(24,004,519	)

Total stockholder’s equity		6,641,570			8,229,535


Total liabilities and stockholders’ equity	$	9,275,613		$	10,943,832

See accompanying notes to consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations


	Years Ended December 31,
	2008			2007
Revenue from operations:
Pipeline operations	$	2,448,831		$	2,494,406
Oil and gas sales		540,579			517,411

Total revenue from operations		2,989,410			3,011,817

Cost of operations:
Pipeline operating expenses		1,722,642			1,788,288
Lease operating expenses		243,450			240,317
Depletion, depreciation and amortizaton		527,972			554,704
Impairment of oil and gas properties		213,563			—
General and administrative expenses		1,953,496			1,996,424
Stock-based compensation		298,275			181,852
Accretion expense		108,020			120,384

Total cost of operations		5,067,418			4,881,969


Loss from operations		(2,078,008	)		(1,870,152	)

Other income (expense):
Interest and other income		120,069			248,637
Loss on disposal of assets		(1,886	)		—

Total other income (expense)		118,183			248,637


Loss before income taxes		(1,959,825	)		(1,621,515	)

Income tax expense		(6,415	)		(4,057	)


Net loss	$	(1,966,240	)	$	(1,625,572	)


Loss per common share:
Basic	$	(0.17	)	$	(0.14	)

Diluted	$	(0.17	)	$	(0.14	)


Weighted average number of common shares outstanding:
Basic		11,642,391			11,568,311

Diluted		11,642,391			11,568,311

See accompanying notes to consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders’ Equity


	Common				Additional					Total
	Stock		Common		Paid-In		Accumulated			Stockholders’
	Shares		Stock		Capital		Deficit			Equity

Balance at December 31, 2006		11,555,452	$	115,555	$	31,835,137	$	(22,378,947	)	$	9,571,745

Issuance under stock plans		27,938		279		22,071		—			22,350
Common stock issued for services		26,973		270		78,890		—			79,160
Stock-based compensation		—		—		181,852		—			181,852
Net loss		—		—		—		(1,625,572	)		(1,625,572	)


Balance at December 31, 2007		11,610,363	$	116,104	$	32,117,950	$	(24,004,519	)	$	8,229,535

Issuance under stock plans		—		—		—		—			—
Common stock issued for services		80,880		808		79,192		—			80,000
Stock-based compensation		—		—		298,275		—			298,275
Net loss		—		—		—		(1,966,240	)		(1,966,240	)


Balance at December 31, 2008		11,691,243	$	116,912	$	32,495,417	$	(25,970,759	)	$	6,641,570

See accompanying notes to consolidated financial statements.

Remainder of Page Intentionally Left Blank

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows


	Years Ended December 31,
	2008			2007
OPERATING ACTIVITIES
Net loss	$	(1,966,240	)	$	(1,625,572	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		527,972			554,704
Impairment of oil and gas properties		213,563			—
Accretion expense		108,020			120,384
Stock-based compensation		298,275			181,852
Common stock issued for services		80,000			79,160
Bad debt expense		26,699			—
Loss on disposal of assets		1,886			—
Changes in operating assets and liabilities:
Accounts receivable		224,563			480,342
Prepaid expenses and other current assets		73,452			(159,991	)
Abandonment costs incurred		(18,537	)		(76,290	)
Accounts payable, accrued expenses and other liabilities		(169,737	)		262,245

Net cash used in operating activities		(600,084	)		(183,166	)

INVESTING ACTIVITIES
Exploration and development costs		(749,088	)		—
Capital expenditures		(12,731	)		(111,552	)

Net cash used in investing activities		(761,819	)		(111,552	)

FINANCING ACTIVITIES
Proceeds from exercise of stock options		—			22,350

Net cash provided by financing activities		—			22,350

Decrease in cash and cash equivalents		(1,361,903	)		(272,368	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		5,226,779			5,499,147

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	3,864,876		$	5,226,779


Non-cash activities:
Change in estimate for asset retirement obligations and related fixed assets	$	—		$	35,205

See accompanying notes to consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Notes to Consolidated Financial Statements

(1)		Organization and Significant Accounting Policies

		Organization

		Blue Dolphin Energy Company was incorporated in Delaware in January 1986 to engage in oil and gas exploration, production and acquisition activities and oil and gas transportation and marketing. We were formed pursuant to a reorganization effective June 9, 1986.

		Principles of Consolidation

		Our consolidated financial statements include the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

		Accounting Estimates

		We have made a number of estimates and assumptions relating to the reporting of consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. This includes the estimated useful life of pipeline assets, valuation of stock-based payments and reserve information, which affects the depletion calculation as well as the full cost ceiling limitation. While we believe current estimates are reasonable and appropriate, actual results could differ from those estimated.

		Reclassifications

		Certain reclassifications of prior year amounts have been made to conform to the current year presentation.

		Cash Equivalents

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

		Oil and Gas Properties

		Oil and gas properties are accounted for using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. We utilize one cost center for all of our properties. Amortization of such costs and estimated future development costs is determined using the unit-of-production method. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.

		Estimated proved oil and gas reserves are based upon reports prepared internally by us. The net carrying value of oil and gas properties, less related deferred income taxes, is limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% discount rate applied) of estimated future net revenues from proved reserves, after giving effect to income taxes, and the lower of cost or estimated fair value of unproved properties. In 2008, our

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

		unamortized cost exceeded the present value of estimated future net revenues and we recorded an impairment to our oil and gas properties of $213,563. Disposition of oil and gas properties are recorded as adjustments to capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

		We capitalize interest on expenditures made in connection with significant exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest has been capitalized for the years reflected herein.

		Pipelines and Facilities

		Pipelines and facilities are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years.

		In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.

		Other Property and Equipment

		Depreciation of furniture, fixtures and other equipment is computed using the straight-line method over estimated useful lives ranging from 3 to 10 years.

		Asset Retirement Obligations

		In August 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations, as amended, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

		SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. If the obligation is settled for other than the carrying amount of the liability, a gain or loss on settlement is recognized.

		We have asset retirement obligations associated with the future abandonment of pipelines and related facilities and offshore oil and gas properties. The following table summarizes our asset retirement obligation transactions during the years ended December 31, 2008 and 2007 (in thousands).

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


	Years Ended December 31,
	2008			2007

Beginning asset retirement obligations	$	2,094		$	2,014
Liabilities incurred		—			36
Liabilities settled		(19	)		(76	)
Accretion expense		108			120


Ending asset retirement obligations	$	2,183		$	2,094

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payments (“SFAS 123(R)”) utilizing the modified prospective approach. Prior to the adoption of SFAS 123(R) we accounted for stock option grants in accordance with APB Opinion No. 25, Accounting for Stock Issued to Employees (the intrinsic value method), and accordingly, recognized no compensation expense when stock options were granted with an exercise price equal to the grant date fair market value of a share of our common stock.

Under the modified prospective approach, SFAS 123(R) applies to new awards and to awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased, or cancelled. Under the modified prospective approach, had there been any awards granted during 2006, compensation expense recognized in the period would have included compensation cost for all share-based payments granted prior to, but not yet vested, based on the grant date fair value estimated in accordance with the original provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). Prior periods were not restated to reflect the impact of adopting the new standard.

Recognition of Oil and Gas Revenue

Sales from producing wells are recognized on the entitlement method of accounting which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at December 31, 2008 was not material.

Recognition of Pipeline Transportation Revenue

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

Allowance for Doubtful Accounts

Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customer’s credit worthiness or

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

other matters affecting the collectability of amounts due from such customers could have a material effect on the results of operations in the period in which such changes or events occur. The Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for individual customer balances. As of December 31, 2008 and 2007, we had recorded an allowance for doubtful accounts of $26,699 and $0 respectively.

Income Taxes

We provide for income taxes using the asset and liability method pursuant to SFAS No. 109, Accounting for Income Taxes and FIN 48. Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Under FIN 48, which we adopted effective January 1, 2007, tax positions are evaluated in a two-step process. The first step is to determine whether it is more likely than not that a tax position will be sustained upon examination. The second step is a measurement process whereby a tax position that meets the more-likely-than-not threshold is calculated to determine the amount of benefit to recognize in the financial statements.

Earnings Per Share

We apply the provisions of Statement of Financial Accounting Standards No. 128, Earnings per Share (“SFAS 128”). SFAS 128 requires the presentation of basic earnings per share (“EPS”) which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. SFAS 128 requires dual presentation of basic EPS and diluted EPS on the face of the consolidated statement of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common shareholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue common stock were converted to common stock that then shared in the earnings of the entity.

Employee stock options and stock warrants outstanding were not included in the computation of diluted earnings per share for the years ended December 31, 2008 and 2007, because their assumed exercise and conversion would have an anti-dilutive effect on the computation of diluted loss per share.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

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


	Year Ended
	December 31,
Basic and Diluted	2008			2007

Net loss	$	(1,966,240	)	$	(1,625,572	)


Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		11,642,391			11,568,311


Per share amount	$	(0.17	)	$	(0.14	)

Environmental

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amounts and timing of payments is fixed or reliably determinable.

Recently Adopted Accounting Pronouncements

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires companies to disclose the fair value of financial instruments according to a fair value hierarchy. Additionally, companies are required to provide certain disclosures regarding instruments within the hierarchy, including a reconciliation of the beginning and ending balances for each major category of assets and liabilities. SFAS No. 157 was effective for our fiscal year beginning January 1, 2008. In February 2008, the FASB issued Staff Positions No. 157-1 and No. 157-2, which partially defer the effective date of SFAS No. 157 for one year for certain nonfinancial assets and liabilities and remove certain leasing transactions from its scope. We adopted SFAS No. 157 on January 1, 2008 with no effect on our consolidated financial statements.

The Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity must report unrealized gains and losses, on items for which the fair value option has been elected, in earnings at each subsequent reporting date. SFAS No. 159 was effective for our fiscal year beginning January 1, 2008. The adoption of SFAS No. 159 did not impact our consolidated financial statements.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Recently Issued Accounting Pronouncements

Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51. In December 2007, the FASB also issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51 (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (previously referred to as minority interests). SFAS 160 also requires that a retained non-controlling interest upon the deconsolidation of a subsidiary be initially measured at its fair value. Upon adoption of SFAS 160, we would be required to report any non-controlling interests as a separate component of stockholders’ equity. We would also be required to present any net income (loss) allocable to non-controlling interests and net income (loss) attributable to the stockholders of the company separately in our consolidated statements of operations. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. SFAS 160 would have an impact on the presentation and disclosure of the non-controlling interests of any non wholly-owned businesses acquired in the future.

(2)		Fair Value of Financial Instruments

		The carrying values of cash and cash equivalents, accounts receivable and accounts payable, accrued liabilities and other current liabilities approximate fair value due to the short-term maturities of these instruments.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

(3)		Income Taxes

		Income tax expense consisted of $6,415 and $4,057 and was related to state income tax for the years ended 2008 and 2007, respectively.

		The income tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2008 and 2007 are presented below:


	2008			2007
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	5,881,885		$	5,700,789
AMT credit carryforward		11,564			11,564
Basis differences in property and equipment		314,192			151,268


Total deferred tax assets		6,207,641			5,863,981
Less: valuation allowance		(6,207,641	)		(5,863,981	)


Deferred tax assets, net	$	—		$	—

In assessing the recoverability of deferred tax assets, we apply SFAS No. 109 and FIN 48, which we adopted effective January 1, 2007, to determine whether it is more likely than not that some portion or all of the deferred tax assets will be realized. A full valuation allowance against our deferred tax asset was recognized at December 31, 2008 and 2007 due to our uncertainty as to the utilization of the deferred tax assets in the foreseeable future. The net change in the total valuation allowance for the years ended December 31, 2008 and 2007 was an increase of $343,660 and $641,624, respectively.

Our effective tax rate applicable to continuing operations in 2008 and 2007 is as follows:


	Years Ended December 31,
	2008			2007
Expected tax rate		(34.00	%)		(34.00	%)
Change in valuation allowance recognized in earnings		34.33	%		34.25	%

		0.33	%		0.25	%

For federal tax purposes, we have net operating loss carry-forwards (“NOLs”) of approximately $17.3 million at December 31, 2008. These NOLs must be utilized prior to their expiration, which will occur between 2011 and 2028.

We adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes (“SFAS 109”). FIN 48 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.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

		The evaluation of a tax position in accordance with FIN 48 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 FIN 48 have been applied to all of our material tax positions taken through the date of adoption and through the fiscal year ended December 31, 2008. 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 FIN 48. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the new pronouncement.

		In May 2006, the State of Texas enacted a new business tax that is imposed on gross revenues to replace the State’s current franchise tax regime. Although the Texas margins tax (“TMT”) is imposed on an entity’s gross revenues rather than on its net income, certain aspects of the tax make it similar to an income tax. In accordance with the guidance provided in SFAS 109, we have properly determined the impact of the newly-enacted legislation in the determination of our reported state current and deferred income tax liability.

(4)		Warrants

		At December 31, 2008, the range of warrant prices for shares under warrants and the weighted-average remaining contractual life was as follows:

Warrants Outstanding, Fully Vested and Exercisable at December 31, 2008

Weighted Average

Remaining

Contractual Life in

Weighted Average

Exercise Prices

Number Outstanding

Years

Exercise Price

$6.00 to $6.50

16,440

0.3

6.37

These securities were issued in reliance upon the exemption from registration pursuant to Section 4(2) under the Securities Act of 1933, as amended.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

A summary of warrant activity for 2008 and 2007 is as follows:


			Weighted-				Weighted-
			Average				Average
	Number of		Exercise		Warrants		Exercise
	Warrants		Price		Exercisable		Price

Outstanding, December 31, 2006		16,440	$	5.39		16,440	$	5.39
Granted		—		—
Exercised		—		—

Outstanding, December 31, 2007		16,440	$	5.88		16,440	$	5.88
Granted		—		—
Exercised		—		—

Outstanding, December 31, 2008		16,440	$	6.37		16,440	$	6.37

(5)		Stock Options

		Effective April 14, 2000, after approval by our stockholders, we adopted the 2000 Stock Incentive Plan (the “2000 Plan”). Under the 2000 Plan, we are able to make awards of stock-based compensation. The number of shares of common stock reserved for grants of incentive stock options (“ISOs”) and other stock-based awards was increased from 650,000 shares to 1,200,000 shares after approval by our stockholders at the 2007 Annual Meeting of Stockholders, which was held on May 30, 2007. As of December 31, 2008, we had 210,040 shares of common stock remaining available for future grants. Options granted under the 2000 Plan have contractual terms from six to ten years. The exercise price of ISOs cannot be less than 100% of the fair market value of a share of our common stock determined on the grant date. All ISO awards granted in previous years vested immediately, however, 200,000 ISOs granted in May 2007 and 75,000 ISO’s granted in August 2008 have a three year vesting period and 150,000 ISOs granted in October 2007 have a two year vesting period. An additional 28,500 options were granted in October 2007 that vested immediately. Although the 2000 Plan provides for the granting of other incentive awards, only ISOs and non-statutory stock options have been issued under the 2000 Plan. The 2000 Plan is administered by the Compensation Committee of our Board of Directors.

		SFAS 123(R) states that a tax deduction is permitted for stock options exercised during the period, generally for the excess of the price at which stock issued from exercise of the options are sold over the exercise price of the options. Tax benefits are to be shown on the Statement of Cash Flows as financing cash inflows. Any tax deductions we receive from the exercise of stock options for the foreseeable future will be applied to the valuation allowance in determining our net operating loss carry forward.

		Additionally, we utilized the alternate transition method (simplified method) for calculating the beginning balance in the pool of excess tax benefits in accordance with FASB Staff Position FAS123(R)-3, Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.

		Pursuant to SFAS 123(R), we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. The following assumptions were used to determine the fair value of stock options granted during the years ended December 31, 2008 and 2007.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


	Years Ended December 31,
	2008			2007
Stock options granted		75,000			378,500
Risk-free interest rate		3.23	%		4.31 to 4.80	%
Expected term, in years		6.00			3.75 to 5.97
Expected volatility		90.70	%		81.67 to 92.40	%
Dividend yield		0.00	%		0.00	%

Expected volatility used in the model is based on the historical volatility of our common stock and is weighted 50% for the historical volatility over a past period equal to the expected term and 50% for the historical volatility over the past two years prior to the grant date. This weighting method was chosen to account for the significant changes in our financial condition beginning approximately three years ago. These changes include the improvement in our working capital, improved pipeline throughput and the reduction and ultimate elimination of our outstanding debt.

The expected term of options granted used in the model represents the period of time that options granted are expected to be outstanding. The method used to estimate the expected term is the “simplified” method as allowed under the provisions of the Securities and Exchange Commission’s Staff Accounting Bulletin No. 107. This number is calculated by taking the average of the sum of the vesting period and the original contract term. The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of the grant. As we have not declared dividends on our common stock since we became a public entity, no dividend yield was used. No forfeiture rate was assumed due to the forfeiture history for this type of award. Actual value realized, if any, is dependent on the future performance of our common stock and overall stock market conditions. There is no assurance that the value realized by an optionee will be at or near the value estimated by the Black-Scholes-Merton option-pricing model.

At December 31, 2008, there were a total of 555,559 shares of common stock reserved for issuance upon exercise of outstanding options under the 2000 Plan. A summary of the status of our stock options granted to key employees, officers and directors, for the purchase of shares of common stock, is as follows:

Remainder of Page Intentionally Left Blank

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


	Year Ended December 31, 2008
						Weighted
				Weighted		Average		Aggregate
				Average		Remaining		Intrinsic
	Shares			Exercise Price		Contractual Life		Value

Options outstanding at December 31, 2006		143,997		$	1.56

Options granted		378,500		$	2.93

Options exercised		(27,938	)	$	0.80

Options expired or cancelled		(3,000	)	$	6.00


Options outstanding at December 31, 2007		491,559		$	2.61

Options granted		75,000		$	1.36

Options exercised		—		$	0.00

Options expired or cancelled		(11,000	)	$	3.10


Options outstanding at December 31, 2008		555,559		$	2.43		6.6	$	—


Options exercisable at December 31, 2008		271,559		$	2.35		5.4	$	—

Remainder of Page Intentionally Left Blank

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

The following table summarizes additional information about stock options outstanding at December 31, 2008:


		Options Outstanding						Options Exercisable
				Average						Weighted
				Remaining						Average
Range of Exercise		Number		Contractual Life		Weighted Average		Number		Exercise
Prices		Outstanding		(Years)		Exercise Price		Exercisable		Price
$0.35 to $0.80			70,830		4.3	$	0.44		70,830	$	0.44
$1.36 to $1.90			98,429		8.1	$	1.44		23,429	$	1.71
$2.81 to $2.99			368,500		7.0	$	2.91		159,500	$	2.88
$	6.00		17,800		1.4	$	6.00		17,800	$	6.00

			555,559						271,559

The following summarizes the net change in non-vested stock options for the years shown:


				Weighted
				Average
				Grant Date
	Shares			Fair Value

Non-vested at December 31, 2006		—		$	0.00
Granted		378,500		$	2.06
Canceled or expired		—		$	0.00
Vested		(28,500	)	$	1.96

Non-vested at December 31, 2007		350,000		$	2.05
Granted		75,000		$	1.03
Canceled or expired		—		$	0.00
Vested		(141,000	)	$	2.00


Non-vested at December 31, 2008		284,000		$	1.83

As of December 31, 2008, there was $379,027 of unrecognized compensation cost related to 284,000 non-vested stock options granted under the existing stock incentive plan, the 2000 Plan. The weighted average period over which the unrecognized compensation cost will be recognized is 14 months. Subsequent to year end, due to the departure of an officer, 75,000 options were forfeited. In subsequent periods, stock compensation expense will be net of the associated expense for the forfeited options.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

(6)		Leases

		We have various operating leases that extend through April 2017. Certain of these operating leases are non-cancelable through May 2010. The following is a schedule of future minimum lease payments under non-cancelable operating leases exceeding one year at December 31, 2008:


	Future
	Minimum
	Lease
Years Ending December 31,	Payments

2009		107,051
2010		172,646

	$	279,697

Rent expense on operating leases for the years indicated are as follows:


	Lease
Years Ended December 31,	Expense
2008	$	116,117
2007	$	102,980

(7)		Commitments and Contingencies

		We are involved in various claims and legal actions arising in the ordinary course of business. In our opinion, the ultimate disposition of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

		Pursuant to the terms of an employment agreement effective May 1, 2007, we are obligated to pay a base salary of $175,000 per year for the three-year term of the agreement.

(8)		Business Segment Information

		Our operations are conducted in two principal business segments: (i) pipeline transportation services and (ii) oil and gas exploration and production. Our segments are managed jointly mainly due to the size of the Company. Our management uses earnings before interest expense and income taxes (“EBIT”) to assess the operating results and effectiveness of our business segments, which consist of our consolidated businesses and investments. We believe EBIT is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income or loss from continuing operations, such as the impact of accounting changes, (ii) income taxes and (iii) interest expense (income). We exclude interest expense (income) and other expense or income not pertaining to the operations of our segments from this measure so that investors may evaluate our current operating results without regard to our financing methods or capital structure. We understand that EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating cash flows.

		Below is a reconciliation of our EBIT (by segment) for each of the two years ended:

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)


	December 31, 2008
	Segment
				Oil and Gas
	Pipeline			Exploration &			Corporate &
	Transportation			Production			Other⁽¹⁾			Total
Revenues	$	2,448,831		$	540,579		$	—		$	2,989,410
Operation cost⁽²⁾		3,389,058			594,247			342,578			4,325,883
Depletion, depreciation and amortization		417,384			317,618			6,534			741,535

EBIT	$	(1,357,611	)	$	(371,286	)	$	(349,112	)	$	(2,078,008	)


Capital expenditures	$	1,033		$	749,088		$	11,698		$	761,819


Identifiable assets⁽³⁾	$	5,073,147		$	560,221		$	3,642,245		$	9,275,613


(1)		Includes unallocated G&A costs associated with corporate maintenance costs and legal expenses. It also includes as identifiable assets corporate available cash of $3.5 million.

(2)		Allocable G&A costs are allocated based on revenues.

(3)		Identifiable Assets contain related legal obligations of each segment including cash, accounts receivable & payable and recorded net assets.


	December 31, 2007
	Segment
				Oil and Gas
	Pipeline			Exploration &			Corporate &
	Transportation			Production			Other⁽¹⁾			Total
Revenues	$	2,494,406		$	517,411		$	—		$	3,011,817
Operation cost⁽²⁾		3,300,130			557,584			469,551			4,327,265
Depletion, depreciation and amortization		413,342			135,650			5,712			554,704

EBIT	$	(1,219,066	)	$	(175,823	)	$	(475,263	)	$	(1,870,152	)


Capital expenditures	$	106,842		$	—		$	4,710		$	111,552


Identifiable assets⁽³⁾	$	5,769,899		$	344,541		$	4,829,392		$	10,943,832


(1)		Includes unallocated G&A costs associated with corporate maintenance costs and legal expenses. It also includes as identifiable assets corporate available cash of $4.7 million.

(2)		Allocable G&A costs are allocated based on revenues.

(3)		Identifiable Assets contain related legal obligations of each segment including cash, accounts receivable & payable and recorded net assets.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Our primary market area is the Texas and Louisiana Gulf Coast region of the United States. We have a concentration of credit risk with customers in the energy industry. Our customers may be similarly affected by changes in economic, regulatory or other factors. Trade receivables are generally not collateralized; however, our customers’ historical and future credit positions are thoroughly analyzed prior to extending credit. Revenues from major customers exceeding 10% of revenues were as follows for the period indicated:


	Oil and Gas		Pipeline
	Sales		Operations		Total

Year Ended December 31, 2008:
Arena Offshore	$	—	$	513,634	$	513,634
W&T Offshore	$	—	$	488,083	$	488,083
Gryphon Exploration Co.	$	—	$	367,153	$	367,153
Apex Oil & Gas	$	—	$	338,836	$	338,836

Year Ended December 31, 2007:
Apex Oil & Gas	$	—	$	809,420	$	809,420
W&T Offshore	$	—	$	519,866	$	519,866
Gryphon Exploration Co.	$	—	$	341,406	$	341,406

(9)		Supplemental Oil and Gas Information

		The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, Disclosures about Oil and Gas Producing Activities.

		Associated with our non-operating interest in High Island Block 37, we recognized gas and oil sales revenues of approximately $250,000 and $300,000 in 2008 and 2007, respectively, and lease operating expenses of approximately $127,000 and $32,000 in 2008 and 2007, respectively. We have a working interest of approximately 2.8% in two producing wells in the block. The A-2 well resumed production in the first quarter of 2009 after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008.

		Associated with our non-operated interest in High Island Block 115, we recognized gas and oil sales revenues of approximately $290,000 and $30,000 in 2008 and 2007, respectively, and lease operating expenses of approximately $116,000 and $8,000 in 2008 and 2007, respectively. We have a working interest of 2.5% in one zone of a single well in the lease. The well resumed production in the first quarter of 2009 after being shut-in due to damage to third party onshore facilities resulting from Hurricane Ike in September 2008.

		Estimated Quantities of Proved Oil and Gas Reserves (unaudited)

		Set forth below is a summary of the changes in the estimated quantities of our crude oil and condensate, and gas reserves for the periods indicated, as estimated by us at December 31, 2008 and 2007. All of our reserves are located within the United States of America. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Proved reserves are estimated quantities of gas, crude oil, and condensate which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.


	Oil			Gas
Quantity of Oil and Gas Reserves	(Bbls)			(Mcf)

Total proved reserves at December 31, 2006:		153			108,047
Revisions to previous estimates		64			(22,045	)
Extensions, discoveries, improved recovery and other additions		806			164,456
Purchase of reserves in place		—			—
Sales of reserves in place		—			—
Production		(177	)		(72,787	)


Total proved reserves at December 31, 2007		846			177,671


Revisions to previous estimates		(297	)		10,827
Extensions, discoveries, improved recovery and other additions		337			14,440
Purchase of reserves in place		—			—
Sales of reserves in place		—			—
Production		(117	)		(44,720	)


Total proved reserves at December 31, 2008		769			158,218


Proved developed reserves:
December 31, 2008		769			158,218
December 31, 2007		846			177,671

Total proved reserves:
December 31, 2008		769			158,218
December 31, 2007		846			177,671

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Capitalized Costs of Oil and Gas Producing Activities

The following table sets forth the aggregate amounts of capitalized costs relating to our oil and gas producing activities and the aggregate amount of related accumulated depletion, depreciation, amortization as of:


	December 31,			December 31,
	2008			2007

Unproved properties and prospect generation costs not being amortized	$	—		$	—

Proved properties being amortized		1,286,700			751,175


Total capitalized costs		1,286,700			751,175

Accumulated depreciation, depletion and amortization		(776,467	)		(675,855	)


Net capitalized costs	$	510,233		$	75,320

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property acquisition, disposition, exploration and development activities during the periods indicated:


	Years Ended December 31,
	2008		2007

Costs incurred:
Acquisition of proved properties	$	—	$	—
Acquisition of unproved properties		—		—

Exploration costs		749,088		—
Development costs		—		—


Total costs incurred	$	749,088	$	—

We did not incur costs in the acquisition of oil and gas properties in 2008 or 2007.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

Results of Operations for Oil and Gas Producing Activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest expense and interest income.


	Years Ended December 31,
	2008			2007

Revenues from oil and gas producing activities	$	540,579		$	517,411
Production costs		(243,450	)		(240,317	)
Depreciation, depletion, and amortization		(104,055	)		(135,650	)
Impairment of oil and gas properties		(213,563	)		—

Pretax income from producing activities		(20,489	)		141,444

Income tax expense/estimated loss carryforward benefit		324			(354	)


Results of oil and gas producing activities (excluding corporate overhead and interest costs)	$	(20,165	)	$	141,090

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

The following table reflects the Standardized Measure of Discounted Future Net Cash Flows relating to our interest in proved oil and gas reserves for:


	Years Ended December 31,
	2008			2007

Future cash inflows	$	866,600		$	1,342,000
Future development costs		—			(395,000	)
Future production costs		(267,900	)		(129,000	)
Future income taxes		—			(278,120	)
10% discount factor		(88,500	)		(70,620	)


Standardized measure of discounted future net cash inflows (outflows)	$	510,200		$	469,260


Future net cash flows at each year end, as reported in the above schedule, were determined by summing the estimated annual net cash flows computed by: (1) multiplying estimated quantities of proved reserves to be produced during each year by year-end prices and (2) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on year-end costs).

Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and available net operating loss carry-forwards. The annual future net cash flows were discounted, using a prescribed 10% rate, and summed to determine the standardized measure of discounted future net cash flow.

BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)

We caution readers that the standardized measure information which places a value on proved reserves is not indicative of either fair market value or present value of future cash flows. Other logical assumptions could have been used for this computation which would likely have resulted in significantly different amounts. Such information is disclosed solely in accordance with Statement 69 and the requirements promulgated by the Securities Exchange Commission to provide readers with a common base for use in preparing their own estimates of future cash flows and for comparing reserves among companies. We do not rely on these computations when making investment and operating decisions. Principal changes in the Standardized Measure of Discounted Future Net Cash Flows attributable to our proved oil and gas reserves for the periods indicated are as follows:


	Years Ended December 31,
	2008			2007

Sales and transfers, net of production costs	$	(297,129	)	$	(277,094	)
Net change in sales and transfer prices, net of production costs		(377,061	)		16,380
Extension, discoveries and improved recovery, net of future production and development costs		404,129			987,094
Development costs incurred during the period that reduced future development costs		18,500			76,290
Changes in estimated future development cost		67,296			(252	)
Revisions of quantity estimates		(27,964	)		(132,353	)
Accretion of discount		10,700			8,900
Net change in income taxes		241,740			(255,680	)
Change in production rates (timing) and other		762			(12,765	)


Net change	$	40,973		$	410,520

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

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the year covered by this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon this evaluation, as of December 31, 2008, the Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including the Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-5(f) under the Exchange Act). Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. Our management has concluded that, as of December 31, 2008, our internal control over financial reporting is effective based on these criteria. This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Our management, including our Chief Executive Officer and our Principal Accounting and Financial Officer, does not expect our internal control over financial reporting to prevent all error or fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must take into account resource constraints. The benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Our internal control over financial reporting, however, is designed to provide reasonable assurance that the objectives of internal control over financial reporting are met.

Changes In Internal Controls over Financial Reporting

There have been no changes made in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, the internal control over financial reporting, during the period covered by this report.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10 is incorporated by reference to our definitive proxy statement relating to our 2009 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference to our definitive proxy statement relating to our 2009 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

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

Equity Compensation Plan Information

The information required by Item 12 is incorporated by reference to our definitive proxy statement relating to our 2009 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

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

The information required by Item 13 is incorporated by reference to our definitive proxy statement relating to our 2009 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 is incorporated by reference to our definitive proxy statement relating to our 2009 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

Remainder of Page Intentionally Left Blank

PART IV

ITEM 15. EXHIBITS


	No.			Description

		3.1	(1)	Amended and Restated Certificate of Incorporation of the Company.

		3.2	(9)	Amended and Restated Bylaws of the Company.

		4.1	(2)	Specimen Certificate of our Company common stock.

		4.3	(7)	Form of Promissory Note issued pursuant to the Note and Warrant Purchase Agreement dated September 8, 2004.

*		10.1	(3)	Blue Dolphin Energy Company 2000 Stock Incentive Plan.

*		10.2	(4)	Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan.

		10.3	(5)	Second Amendment to the Blue Dolphin Energy Company 2000 Stock Incentive Plan.

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

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

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

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

		10.8	(12)	Placement Agency Agreement by and between Blue Dolphin Energy Company and Starlight Investments, LLC dated May 27, 2005.

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

		14.2	(11)	Code of Ethics applicable to the Chairman, Chief Executive Officer and Senior Financial Officer.

**		21.1		List of Subsidiaries of the Company.

**		23.1		Consent of UHY LLP.

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

**		31.2		T. Scott Howard Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.


*		Management Compensation Plan.

**		Filed herewith.


(1)		Incorporated herein by reference to Exhibits filed in connection with the definitive Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated October 13, 2004 (Commission File No. 000-15905).

(2)		Incorporated herein by reference to Exhibits filed in connection with Form 10-K of Blue Dolphin Energy Company for the year ended December 31, 1989 under the Securities and Exchange Act of 1934, dated March 30, 1990 (Commission File No. 000-15905).

(3)		Incorporated herein by reference to Exhibits filed in connection with the Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated May 18, 2000 (Commission File No. 000-15905).

(4)		Incorporated herein by reference to Exhibits filed in connection with the definitive Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated April 16, 2003 (Commission File No. 000-15905).

(5)		Incorporated herein by reference to Exhibits filed in connection with the definitive Proxy Statement of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated April 27, 2007 (Commission File No. 000-15905).

(6)		Incorporated herein by reference to Exhibits filed in connection with Form 10-KSB of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated July 23, 2002 (Commission File No. 000-15905).

(7)		Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated September 14, 2004 (Commission File No. 000-15905).

(8)		Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated December 6, 2004 (Commission File No. 000-15905).

(9)		Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated December 26, 2007 (Commission File No. 000-15905).

(10)		Incorporated herein by reference to Exhibits filed in connection with Form 8-K of Blue Dolphin Energy Company under the Securities and Exchange Act of 1934, dated March 2, 2005 (Commission File No. 000-15905).

(11)		Incorporated herein by reference to Exhibit 14.1 filed in connection with Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2004 under the Securities Exchange Act of 1934, dated March 25, 2005 (Commission File No. 000-15905).

*		Management Compensation Plan.

**		Filed herewith.


(12)		Incorporated herein by reference to Exhibit 10.9 filed in connection with Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905).

(13)		Incorporated herein by reference to Exhibit 10.10 filed in connection with Form 10-KSB of Blue Dolphin Energy Company for the year ended December 31, 2005 under the Securities Exchange Act of 1934, dated March 30, 2006 (Commission File No. 000-15905).

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BLUE DOLPHIN ENERGY COMPANY (Registrant)
	By:	/s/ Ivar Siem
		Ivar Siem
		(Chairman and CEO)
	Date: March 12, 2009

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


Signature	Title	Date

/s/ Ivar Siem Ivar Siem	Chairman and CEO (Principal Executive Officer)	March 12, 2009

/s/ T. Scott Howard T. Scott Howard	Accounting Manager, Treasurer and Assistant Secretary (Principal Accounting and Financial Officer)	March 12, 2009

/s/ Laurence N. Benz Laurence N. Benz	Director	March 12, 2009

/s/ John N. Goodpasture John N. Goodpasture	Director	March 12, 2009

/s/ Harris A. Kaffie Harris A. Kaffie	Director	March 12, 2009

/s/ Erik Ostbye Erik Ostbye	Director	March 12, 2009