10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2011

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

For the transition period from                     to                    

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

801 Travis Street, Suite 2100, Houston, Texas 77002
(Address of principal executive offices)

(713) 568-4725
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ Noo

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

Large accelerated filer o Accelerated filero 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

Number of shares of common stock, par value $0.01 per share (the “Common Stock”) outstanding as of November 3, 2011:      2,098,390

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES
INDEX TO QUARTERLY REPORT
ON FORM 10-Q

PART I. FINANCIAL INFORMATION		3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Operations (Unaudited)	4
	Condensed Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	19
Item 4.	Controls and Procedures	19
PART II. OTHER INFORMATION		20
Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	20
Item 3.	Defaults Upon Senior Securities	20
Item 4.	(Removed and Reserved)	20
Item 5.	Other Information	20
Item 6.	Exhibits	21
SIGNATURES		22
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Balance Sheets

	September 30,			December 31,
	2011			2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,643,508		$	625,854
Accounts receivable, net of allowance for doubtful accounts		716,750			598,391
Prepaid expenses and other current assets		83,163			213,071
Loan receivable, net of allowance for loan receivable		—			—
Total current assets		3,443,421			1,437,316
Property and equipment, at cost:
Oil and gas properties (full-cost method)		2,377,041			2,222,535
Pipelines		4,342,480			4,659,686
Onshore separation and handling facilities		1,344,455			1,919,402
Land		473,225			860,275
Other property and equipment		557,374			503,813
		9,094,575			10,165,711
Less: Accumulated depletion, depreciation and amortization		5,233,243			5,630,730
Total property and equipment, net		3,861,332			4,534,981
Loan receivable, net of allowance for loan receivable		—			—
Other assets		9,463			9,463
Total assets	$	7,314,216		$	5,981,760
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	463,094		$	543,327
Note payable — insurance		—			124,936
Asset retirement obligations, current portion		138,538			192,470
Accrued expenses and other current liabilities		39,598			2,142
Total current liabilities		641,230			862,875
Long-term liabilities:
Asset retirement obligations, net of current portion		2,351,975			2,535,386
Total liabilities		2,993,205			3,398,261
Commitments and contingencies
Stockholders’ equity:
Common stock ($0.01 par value, 100,000,000 shares authorized, 2,098,390 and 2,078,514 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively)
		20,984			20,785
Additional paid-in capital		33,753,061			33,693,260
Accumulated deficit		(29,453,034	)		(31,130,546	)
Total stockholders’ equity		4,321,011			2,583,499
Total liabilities and stockholders’ equity	$	7,314,216		$	5,981,760

See accompanying notes to the condensed consolidated financial statements.

3

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Revenue from operations:
Pipeline operations	$	219,006	$	502,369		$	829,011	$	1,393,848
Oil and gas sales		301,417		237,940			1,004,148		278,161
Total revenue from operations		520,423		740,309			1,833,159		1,672,009
Cost of operations:
Pipeline operating expenses		532,931		243,531			999,297		855,842
Lease operating expenses		286,439		221,019			816,718		250,031
Depletion, depreciation and amortizaton		123,355		217,105			406,891		463,806
Recovery on previous allowance for doubtful loan receivable		—		(201,000	)		—		(201,000	)
General and administrative		273,567		286,288			1,056,203		1,084,537
Stock-based compensation		20,000		20,000			60,000		113,760
Accretion expense		32,805		30,563			98,884		88,678
Total cost of operations		1,269,097		817,506			3,437,993		2,655,654
Gain on sale of property and equipment		3,267,070		—			3,267,070		—
Income (Loss) from operations		2,518,396		(77,197	)		1,662,236		(983,645	)
Other income:
Interest and other income		5,138		8,115			15,276		18,872
Income (Loss) before income taxes		2,523,534		(69,082	)		1,677,512		(964,773	)
Income taxes		—		—			—		—
Net income (loss)	$	2,523,534	$	(69,082	)	$	1,677,512	$	(964,773	)
Income (Loss) per common share
Basic	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)
Diluted	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)
Weighted average number of common shares outstanding
Basic		2,094,438		1,967,278			2,088,581		1,793,365
Diluted		2,095,166		1,967,278			2,091,428		1,793,365

See accompanying notes to the condensed consolidated financial statements.

4

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
	2011			2010
Operating Activities:
Net income (loss)	$	1,677,512		$	(964,773	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depletion, depreciation and amortization		406,891			463,806
Gain on sale of property and equipment		(3,267,070	)		—
Recovery on previous allowance for doubtful loan receivable		—			(201,000	)
Accretion of asset retirement obligations		98,884			88,678
Stock-based compensation		60,000			113,760
Changes in operating assets and liabilities:
Accounts receivable		(118,359	)		(62,357	)
Prepaid expenses and other assets		129,908			171,695
Abandonment costs incurred		(336,227	)		(38,996	)
Accounts payable, accrued expenses and other current liabilities		(42,777	)		11,305
Net cash used in operating activities		(1,391,238	)		(417,882	)
Investing Activities:
Purchases of property and equipment		(216,172	)		(58,719	)
Proceeds from sale of property and equipment		3,750,000			—
Net cash provided by (used in) investing activities		3,533,828			(58,719	)
Financing Activities:
Payments on insurance finance note		(124,936	)		(173,479	)
Net cash used in financing activities		(124,936	)		(173,479	)
Net increase (decrease) in cash and cash equivalents		2,017,654			(650,080	)
Cash and Cash Equivalents at Beginning of Period		625,854			1,016,483
Cash and Cash Equivalents at End of Period	$	2,643,508		$	366,403
Supplemental Information:
Non-cash investing and financing activities
Purchase of property and equipment with company stock	$	—		$	685,714
Property and equipment acquired as partial settlement of loan receivable	$	—		$	201,000
Increase in asset retirement obligation and property and equipment	$	—		$	391,369

See accompanying notes to the condensed consolidated financial statements.

5

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

(1) Organization

Company Summary

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

• Blue Dolphin Pipe Line Company (“BDPL”), 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.

Business Segments

We are engaged in two lines of business: (i) pipeline transportation services to producers/shippers, and (ii) oil and gas exploration and production. Our pipeline assets are located offshore and onshore in the Texas Gulf Coast area and our leasehold interests in properties are located in the U.S. Gulf of Mexico and the North Sumatra Basin in offshore Indonesia.

(2) Significant Accounting Policies

Principles of Consolidation

We have prepared our condensed consolidated financial statements without audit, in accordance with U.S. generally accepted accounting principles (“GAAP”) as codified by the Financial Accounting Standards Board (“FASB”) in its Accounting Standards Codification (“ASC”), pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). In the opinion of management, such condensed consolidated financial statements reflect all adjustments necessary to present fair condensed consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

Our accompanying unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our annual report on Form 10-K and Amendment No. 1 on Form 10-K/A for the fiscal year ended December 31, 2010 (“Annual Report”). The results of operations for the three and nine months ended September 30, 2011, are not necessarily indicative of the results of operations to be expected for the year ending December 31, 2011.

Accounting Estimates

We have made a number of estimates and assumptions related to the reporting of condensed consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these unaudited condensed consolidated financial statements in conformity with GAAP. This includes assessing the realization of an outstanding note receivable, the estimated useful life of pipeline assets, valuation of stock-based payments and reserve information, which affects the depletion calculation and the full-cost ceiling limitation. While we believe current estimates are reasonable and appropriate, actual results could differ from those estimated.

Going Concern

Our condensed consolidated financial statements, which have been prepared in accordance with GAAP, contemplated that we would continue as a going concern. As such, our condensed consolidated financial statements do not contain any adjustments that might result if we were unable to continue as a going concern.

6

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

On August 3, 2011, we received proceeds of approximately $3.7 million in cash pursuant to the sale of a portion of our onshore facilities and pipeline assets. We anticipate that our current cash reserves will provide us with sufficient cash to fund our operations beyond the next twelve months. See Note (9), Disposition of Assets, in the “Notes to Condensed Consolidated Financial Statements” included in this report.

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. We maintain cash and cash equivalent balances at one financial institution that is insured by the Federal Deposit Insurance Corporation (the “FDIC”). 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.

In October 2008, the FDIC amended its deposit insurance provisions to increase the basic limit amount from $100,000 to $250,000 per depositor. The coverage increase, which was intended to be temporary, was to revert back to $100,000 per depositor limit on December 31, 2009. However, in May 2009, the FDIC extended the coverage date through December 31, 2013. The temporary increase was made permanent in 2010 by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Accounts Receivable and 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 customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all aged accounts receivables for collectability and establish an allowance as necessary for individual customer balances. As of September 30, 2011 and December 31, 2010, there was no allowance recorded related to trade accounts receivable.

Oil and Gas Properties

We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. We use one cost center for domestic properties and one cost center for foreign properties. Amortization of such costs and estimated future development costs are 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.

Impairment of Oil and Gas Properties

We account for our oil and natural gas exploration and development activities using the full cost method of accounting. 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 a “ceiling,” which is determined based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. Our ceiling for the three and nine months ended September 30, 2011, was calculated using domestic prices of $94.50 per barrel of oil and $4.09 per MMbtu of gas and an international price of $107.59 per barrel of oil. Our ceiling for the three and nine months ended September 30, 2010, was calculated using domestic prices of $77.61 per barrel of oil and $4.42 per MMbtu of gas.

7

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

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 the ASC on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom. We did not have any impairment of our pipelines and facilities for the three and nine month periods ended September 30, 2011 and 2010. During the quarter ended September 30, 2011, BDPL sold its eighty-three and one-third percent (83⅓%) undivided interest in the Buccaneer Pipeline to Sunoco Partners Marketing and Terminals L.P. (“Sunoco”). BDPL still maintains its 83⅓% undivided interest in the Galveston Area Block 350 Pipeline, as well as an 83⅓% undivided interest in the Omega Pipeline.

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.

Stock-Based Compensation

Stock-based compensation is recognized in our condensed consolidated financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the condensed consolidated financial statements on a straight-line basis over the vesting period of the entire award.

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 September 30, 2011 and 2010 was not material.

Recognition of Pipeline Transportation Revenue

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

(3) Business Segment Information

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

8

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Following is a reconciliation of our EBIT (by business segment) for the three months ended September 30, 2011, and at September 30, 2011:

	Three Months Ended September 30, 2011
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)			Total
Revenues	$	219,006	$	301,418		$	—		$	520,424
Operation cost(2)		641,004		399,174			105,565			1,145,743
Depletion, depreciation and amortization		90,254		32,445			656			123,355
Gain on sale of property and equipment		3,267,070		—			—			3,267,070
EBIT	$	2,754,818	$	(130,202	)	$	(106,220	)	$	2,518,396
Capital expenditures	$	8,105	$	130,704		$	53,561		$	192,370
Identifiable assets(3)	$	5,151,988	$	1,788,678		$	373,550		$	7,314,216

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of approximately $57,000
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Following is a reconciliation of our EBIT (by business segment) for the three months ended September 30, 2010, and at September 30, 2010:

	Three Months Ended September 30, 2010
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)		Total
Revenues	$	502,369	$	237,940		$	—	$	740,309
Operation cost(2)		333,715		335,987			131,699		801,401
Depletion, depreciation and amortization		105,043		110,881			1,181		217,105
Recovery on previous allowance for doubtful loan receivable		—		—			201,000		201,000
EBIT	$	63,611	$	(208,928	)	$	68,120	$	(77,197	)
Capital expenditures	$	—	$	1,135,802		$	201,000	$	1,336,802
Identifiable assets(3)	$	4,123,478	$	1,257,593		$	363,935	$	5,745,006

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of $0.4 million.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

9

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Following is a reconciliation of our EBIT (by business segment) for the nine months ended September 30, 2011, and at September 30, 2011:

	Nine Months Ended September 30, 2011
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)			Total
Revenues	$	829,011	$	1,004,148		$	—		$	1,833,159
Operation cost(2)		1,446,655		1,255,077			329,370			3,031,102
Depletion, depreciation and amortization		292,745		111,627			2,519			406,891
Gain on sale of property and equipment		3,267,070		—			—			3,267,070
EBIT	$	2,356,681	$	(362,556	)	$	(331,889	)	$	1,662,236
Capital expenditures	$	8,105	$	154,506		$	53,561		$	216,172
Identifiable assets(3)	$	5,151,988	$	1,788,678		$	373,550		$	7,314,216

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of approximately $57,000.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Following is a reconciliation of our EBIT (by business segment) for the nine months ended September 30, 2010, and at September 30, 2010:

	Nine Months Ended September 30, 2010
	Segment
				Oil and Gas
	Pipeline			Exploration &			Corporate &
	Transportation			Production			Other(1)			Total
Revenues	$	1,393,848		$	278,161		$	—		$	1,672,009
Operation cost(2)		1,657,109			395,032			340,707			2,392,848
Depletion, depreciation and amortization		315,128			144,729			3,949			463,806
Recovery on previous allowance for doubtful loan receivable		—			—			201,000			201,000
EBIT	$	(578,389	)	$	(261,600	)	$	(143,656	)	$	(983,645	)
Capital expenditures	$	—		$	1,135,802		$	201,000		$	1,336,802
Identifiable assets(3)	$	4,123,478		$	1,257,593		$	363,935		$	5,745,006

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of $0.4 million.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

(4) Asset Retirement Obligations

We have asset retirement obligations associated with the future abandonment of our pipelines and related facilities and our offshore oil and gas properties. The following table summarizes our asset retirement obligation transactions during the three months ended September 30, 2011:

Asset retirement obligations as of December 31, 2010	$	2,727,856
Liabilities incurred		—
Liabilities settled		(336,227	)
Accretion expense		98,884
Asset retirement obligations as of September 30, 2011		2,490,513
Less: current portion of asset retirement obligations		138,538
Asset retirement obligations long-term balance as of September 30, 2011	$	2,351,975

(5) Earnings Per Share

We apply the provisions of the ASC for computing earnings per share. The guidance 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. The guidance requires dual presentation of basic EPS and diluted EPS on the face of the condensed 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 quarter ended September 30, 2010, because their assumed exercise and conversion would have an anti-dilutive effect on the computation of diluted loss per share.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Net income (loss)	$	2,523,534	$	(69,082	)	$	1,677,512	$	(964,773	)
Basic
Weighted average number of shares of common stock outstanding		2,094,438		1,967,278			2,088,581		1,793,365
Per share amount	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)
Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		2,095,166		1,967,278			2,091,428		1,793,365
Per share amount	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

(6) Stock Options

We adopted the 2000 Stock Incentive Plan effective April 14, 2000, following approval by our stockholders. An amendment to the plan was approved by our stockholders in 2007. Under the plan, as amended (the “2000 Plan”), we are able to make awards of stock-based compensation. The 2000 Plan has expired and currently no shares may be issued under the plan. 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. 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 Board’s Compensation Committee.

Pursuant to the ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the nine months ended September 30, 2011, and the year ended December 31, 2010.

At September 30, 2011, there were a total of 30,390 shares of common stock reserved for issuance upon exercise of outstanding options under the 2000 Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

					Weighted Average
			Weighted Average		Remaining		Aggregate
	Shares		Exercise Price		Contractual Life		Intrinisic Value
Options outstanding at December 31, 2010		30,390	$	13.29
Options granted		—	$	—
Options exercised		—	$	—
Options expired or cancelled		—	$	—
Options outstanding at September 30, 2011		30,390	$	13.29		2.0	$	408
Options exercisable at September 30, 2011		30,390	$	13.29		2.0	$	408

The following table summarizes additional information about stock options outstanding at September 30, 2011:

	Options Outstanding					Options Exercisable
			Weighted Average					Weighted
			Remaining					Average
Range of Exercise	Number		Contractual Life	Weighted Average		Number		Exercise
Prices	Outstanding		(Years)	Exercise Price		Exercisable		Price
$2.45 to $5.60		10,118	1.6	$	3.06		10,118	$	3.06
$10.85 to $13.30		3,346	0.4	$	11.95		3,346	$	11.95
$19.67		16,926	2.7	$	19.67		16,926	$	19.67
		30,390					30,390

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

We recognized no compensation expense for vested stock options for the three and nine months ended September 30, 2011, compared to $0 and $53,760 for the three and nine months ended September 30, 2010, respectively. As of September 30, 2011, there was no unrecognized compensation cost related to non-vested stock options granted under the 2000 Plan.

We recognized $20,000 and $60,000 of expense related to the fair value issuance of restricted common stock to our independent directors for the three and nine months ended September 30, 2011, respectively.

(7) Loan Receivable

We recorded an allowance for doubtful loan receivable of $1.5 million at December 31, 2009. The loan receivable is associated with a $2.0 million loan, net of credited and recovered amounts (the “Loan”), made to Lazarus Louisiana Refinery II, LLC (“LLRII”) on July 31, 2009 and due on January 31, 2010. As of September 30, 2011, we continued to maintain a full allowance for the uncollected balance of the Loan.

In the second quarter of 2010, we began foreclosure proceedings in Louisiana against the collateral, as well as legal proceedings in Texas against the guaranty that secured the Loan. As a result of a foreclosure auction in Louisiana, we acquired a saltwater disposal well in the third quarter of 2010. Based on the asset’s appraised value, we recovered $201,000 of the allowance for doubtful loan receivable. Under the legal proceedings in Texas, we were granted a partial summary judgment on liability under the promissory note and guaranty in favor of Blue Dolphin. However, the court deferred a ruling on the damages and attorney’s fees to be awarded. On March 28, 2011, our motion for entry of the partial summary judgment was heard before the court. The court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against Lazarus Energy Holdings (“LEH”) and LLRII on the promissory note and guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement. On May 12, 2011, the parties entered into a Rule 11 Agreement in the interests of resolving the claims and disputes related to this matter. The parties have extended the deadline under the Rule 11 Agreement multiple times in an ongoing effort to re-establish a business arrangement that is beneficial to all involved parties.

On July 13, 2011, we entered into a Purchase and Sale Agreement (the “PSA”) with LEH, LLRII, Lazarus Texas Refinery II, LLC, Lazarus Environmental, LLC, Lazarus Energy, LLC (“LE”) and Lazarus Energy Development, LLC whereby we will acquire 100% of the membership interest of LE, the primary asset of which is the Nixon Refinery near Nixon, Texas. Our purchase consideration is the issuance of eighty percent (80%) of our issued and outstanding common stock to LEH, which will represent a change in control of the Company. Closing of the transaction is subject to: (i) LEH obtaining funding of at least $3.7 million for startup of the Nixon Refinery and (ii) approval of the transaction by our stockholders. Upon consummation of the transaction, we have agreed to release LLRII of its obligation to pay the outstanding balance due under the Loan, as well as to release our claims against LLRII and LEH pursuant to the related lawsuit(s).

(8) 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 condensed consolidated financial position, results of operations or cash flows.

(9) Disposition of Assets

Pursuant to an Asset Purchase Agreement, BDPL sold its eighty-three and one-third percent (83⅓%) undivided interest in the Buccaneer Pipeline to Sunoco for proceeds of approximately $3.7 million in cash. The transaction closed on August 3, 2011.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Cautionary Statements

Forward Looking Statements. Certain of the statements included in this quarterly report on Form 10-Q, 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 (the “Exchange Act”), 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 (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) cautions readers that these statements are not guarantees of future performance or results and such statements involve risks and uncertainties that may cause actual results and outcomes to differ materially from those indicated in forward-looking statements. Some of the important factors, risks and uncertainties that could cause actual results to vary from forward-looking statements include:

• ability to continue as a going concern;

• collectability of a $2.0 million loan receivable, net of credited and recovered amounts;

• ability to complete a combination with one or more target businesses;

• ability to secure additional working capital to fund operations;

• ability to monetize our pipeline assets;

• ability to improve pipeline utilization levels;

• performance of third party operators for properties where we have an interest;

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

• volatility of oil and gas prices;

• uncertainties in the estimation of proved reserves, in the projection of future rates of production, the timing of development expenditures and the amount and timing of property abandonment;

• costly changes in environmental and other government regulations for which we are subject;

• adverse changes in the global financial markets; and

• potential delisting of our Common Stock by NASDAQ due to non-compliance with NASDAQ listing requirements.

Additional factors that could cause actual results to differ materially from those indicated in the forward-looking statements are discussed in Item 1A “Risk Factors” in our Annual Report, as filed with the Securities and Exchange Commission (the “SEC”). 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.

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.

Pipeline Operations. We gather and transport oil and natural gas for producers / shippers operating offshore in the vicinity of our pipelines in the Gulf of Mexico to our onshore facilities. We charge the producers / shippers a fee for the offshore transportation of their oil and natural gas. For oil, onshore transportation, facilities services, such as storage, and sale are handled by a third-party. We handle the sale of gas through a chemical plant complex and intrastate pipeline system tie-in. All of our pipeline assets are held by and the business conducted by BDPL. Unless otherwise stated herein, all gas liquid volumes transported are attributable to production from third party producers/shippers.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Pipeline Assets. The following provides a summary of our pipeline segments:

Pipeline		Undivided Ownership			Miles of		Capacity		Storage
Segment	Market	Interest			Pipeline		(MMcf/d)		(Bbls)
BDPS	Gulf of Mexico		83 1/3	%		38		180		—
GA 350	Gulf of Mexico		83 1/3	%		13		65		—
Omega	Gulf of Mexico		83 1/3	%		18		110		—

•

Blue Dolphin Pipeline System (“BDPS”) — The BDPS spans approximately 38 miles and runs from Galveston Area Block 288 offshore to our onshore facilities and the Dow Chemical Plant Complex in Freeport, Texas. The BDPS has an aggregate capacity of approximately 180 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. The BDPS is currently transporting an aggregate of approximately 1.5 MMcf of gas per day from 4 shippers, which represents less than 1% of throughput capacity.

The BDPS includes: (i) approximately 290 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the BDPS’ onshore facilities, pipeline easements and rights-of-way are located, (ii) an offshore platform and (iii) the Blue Dolphin Pipeline. The Blue Dolphin Pipeline, which is a component of the BDPS, consists of two segments:

-  the offshore segment, which transports oil and gas — it 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; and

-  the onshore segment, which transports gas — it is comprised of approximately 2 miles of 16inch pipeline from the onshore facility to a sales point at a chemical plant complex and intrastate pipeline system tie-in in Freeport, Texas.

The BDPS gathers and transports oil and gas from various offshore fields in the Galveston Area of the U.S. Gulf of Mexico to our onshore facilities located in Freeport, Texas. The oil is processed, stored and sold by a third-party. The gas is transported to the Dow Chemical Plant Complex and a major intrastate pipeline system with further downstream tie-ins to other intrastate and interstate pipeline systems and end users.

• 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. The GA 350 Pipeline is currently transporting an aggregate of approximately 13.9 MMcf of gas per day from 2 shippers, which represents 21% of throughput capacity.

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

Exploration and Production. Our oil and gas exploration and production activities include leasehold interests in properties located in the U.S. Gulf of Mexico and the North Sumatra Basin offshore Indonesia. Our leasehold interests, which are held by and the business conducted by Blue Dolphin Petroleum Company, are subject to royalty and overriding royalty interests. We evaluate and manage oil and gas properties by considering geology, reserve life and hydrocarbon mix based on seismic and other data.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Exploration and Production Assets. The following provides a summary of our oil and gas properties:

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

• North Sumatra Basin-Langsa Field — Located offshore Indonesia, the North Sumatra Basin-Langsa Field covers approximately 77 square kilometers and contains two oil fields in waters less than 325 feet deep. Four wells have been completed in the Malacca Formation — one active, the H-4 Well, and three inactive. Production is gathered via a floating production storage and offloading (FPSO) vessel operated by Mitsui Ocean Development & Engineering Co., Ltd. The H-4 Well is currently producing approximately 400 barrels of oil per day.

• High Island Block 115 — High Island Block 115 is located approximately 30 miles southeast of Bolivar Peninsula in an average water depth of approximately 38 feet. The block contains one active well, the B-1 ST2 Well. The B-1 ST2 Well is currently producing approximately 2.4 MMcf of gas per day.

• Galveston Area Block 321 — Galveston Area Block 321 is located approximately 32 miles southeast of Galveston in an average water depth of approximately 66 feet. The block contains one active well, the A-4 Well, which is currently shut-in.

• High Island Block 37 — High Island Block 37, which covers 5,760 acres, is located approximately 15 miles south of Sabine Pass in an average water depth of approximately 36 feet. The block contains one active well, the A-2 Well, and one inactive well, the B-1 Well. The A-2 Well, which was shut-in during the second quarter of 2011, remains off production.

We are primarily dependent on revenue from our pipeline systems and our interests in leasehold properties. We may not be able to continue our operations unless we are able to: (i) generate sufficient funds from our operations, (ii) increase pipeline utilization rates, (iii) offset declining production revenue with revenue from interests in new oil and gas properties, (iv) increase throughput from new or existing shippers/producers, (v) acquire other revenue generating assets at a reasonable price; (vi) monetize our pipeline assets or (vii) obtain financing from other sources.

Results of Operations

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

For the three months ended September 30, 2011 (the “current quarter”), we reported net income of $2,523,534 compared to a net loss of $69,082 for the three months ended September 30, 2010 (the “previous quarter”).

Revenue from Pipeline Operations. Revenue from pipeline operations decreased by $283,363, or 56%, in the current quarter to $219,006 primarily due to a decrease in gas volumes transported. Revenue from the BDPS in the current quarter decreased to approximately $146,100 compared to approximately $415,800 in the previous quarter. Daily gas volumes transported on the BDPS averaged 2 MMcf of gas per day in the current quarter compared to 14 MMcf of gas per day in the previous quarter. Revenue on the GA 350 Pipeline decreased to approximately $72,900 in the current quarter compared to approximately $86,500 in the previous quarter. Daily gas volumes transported on the GA 350 Pipeline averaged 15 MMcf of gas per day in the current quarter compared to 18 MMcf of gas per day in the previous quarter.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Revenue from Oil and Gas Sales. Revenue from oil and gas sales increased by $63,477, or 27%, to $301,417 in the current quarter primarily due to the production from the North Sumatra Basin-Langsa Field.

Our average realized gas price per Mcf in the current quarter was $3.25 compared to $4.02 in the previous quarter. The sales mix by product was 97% oil and 3% gas. Our average realized price per barrel of oil was $115.36 in the current quarter compared to $43.91 in the previous quarter. Revenue breakdown for the current quarter by field was approximately $282,000 for the North Sumatra Basin-Langsa Field, approximately $8,700 for High Island Block 115, approximately $9,700 for Galveston Area Block 321 and approximately $900 for High Island Block 37.

Pipeline Operating Expenses. Pipeline operating expenses in the current quarter increased by $289,400, or 119%, to $532,931 primarily due to increases in consulting fees and legal fees.

Lease Operating Expenses. Lease operating expenses increased in the current quarter by $65,420, or 30%, to $286,439, primarily due to the expenses of the North Sumatra Basin-Langsa Field. Lease operating costs associated with the North Sumatra Basin-Langsa Field totaled approximately $267,200 for the current quarter.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization decreased $93,750, or 43%, to $123,355 in the current quarter primarily due to decreased production of our producing properties. Depletion associated with the North Sumatra Basin-Langsa Field was approximately $8,300.

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

General and Administrative and Stock-Based Compensation. General and administrative and stock-based compensation expenses remained relatively flat, decreasing $12,721, or 4%, in the current quarter. This was primarily a result of continued efforts by management to manage costs.

Gain on Sale of Property and Equipment. During the current quarter, BDPL sold its eighty-three and one-third percent (83 ⅓%) undivided interest in the Buccaneer Pipeline to Sunoco for proceeds of approximately $3.7 million in cash. The gain on the sale was approximately $3.3 million.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

For the nine months ended September 30, 2011 (the “current period”), we reported net income of $1,677,512 compared to a net loss of $964,773 for the nine months ended September 30, 2010 (the “previous period”).

Revenue from Pipeline Operations. Revenue from pipeline operations decreased by $564,837, or 41%, in the current period to $829,011 primarily due to a decrease in gas volumes transported. Revenue from the BDPS in the current period decreased to approximately $619,400 compared to approximately $1,140,000 in the previous period. Daily gas volumes transported on the BDPS averaged 5 MMcf of gas per day in the current period compared to 14 MMcf of gas per day in the previous period. Revenue on the GA 350 Pipeline decreased to approximately $209,600 in the current period compared to approximately $253,000 in the previous period. Daily gas volumes transported on the GA 350 Pipeline averaged 16 MMcf of gas per day in the current period compared to 18 MMcf of gas per day in the previous period.

Revenue from Oil and Gas Sales. Revenue from oil and gas sales increased by $725,987, or 261%, to $1,004,148 in the current period primarily due to the production from the North Sumatra Basin-Langsa Field.

Our average realized gas price per Mcf in the current period was $3.85 compared to $4.13 in the previous period. The sales mix by product was 92% oil and 8% gas. Our average realized price per barrel of oil was $112.27 in the current period compared to $44.21 in the previous period. Revenue breakdown for the current period by field was approximately $902,000 for the North Sumatra Basin-Langsa Field, approximately $66,200 for High Island Block 115, approximately $26,700 for Galveston Area Block 321 and approximately $9,200 for High Island Block 37.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Pipeline Operating Expenses. Pipeline operating expenses in the current period increased by $143,455, or 17%, to $999,297 primarily due to increases in consulting fees and legal fees. The increases were partially offset by decreases in insurance expense and chemical expense.

Lease Operating Expenses. Lease operating expenses increased in the current period by $566,687, or 226%, to $816,718, primarily due to the expenses of the North Sumatra Basin-Langsa Field. Lease operating costs associated with the North Sumatra Basin-Langsa Field totaled approximately $758,300 for the current period.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization decreased $56,915, or 12%, to $406,891 in the current period primarily due decreased production of our producing properties. Depletion associated with the North Sumatra Basin-Langsa Field was approximately $26,972.

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

General and Administrative and Stock-Based Compensation. General and administrative and stock-based compensation expenses remained relatively flat, decreasing $82,094, or 7%, in the current period. This was primarily a result of continued efforts by management to manage costs.

Gain on Sale of Property and Equipment. During the current period, BDPL sold its eighty-three and one-third percent (83 ⅓%) undivided interest in the Buccaneer Pipeline to Sunoco for proceeds of approximately $3.7 million in cash. The gain on the sale was approximately $3.3 million.

Liquidity and Capital Resources

Sources and Uses of Cash. Our primary source of cash is cash flow from operations and cash on hand. During the current period, we had positive cash flow of approximately $2,018,000, primarily as a result of the sale of a portion of our Freeport, Texas assets to Sunoco. Our available cash resources increased from $625,854 at December 31, 2010, to $2,643,508 at September 30, 2011 as a result of proceeds of approximately $3.7 million in cash pursuant to an Asset Purchase Agreement whereby BDPL sold its eighty-three and one-third (83 ⅓%) undivided interest in the Buccaneer Pipeline to Sunoco.

We do not enter into any hedges or any type of derivatives to offset changes in commodity prices. We also do not have any outstanding debt or a credit facility with a bank or institution that may restrict us from issuing debt or common stock.

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

Remainder of Page Intentionally Left Blank

18

BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

	Nine Months Ended
	September 30,
	2011			2010
Cash frow from operations	$	(1,023,783	)	$	(964,773	)
Loss from operations		(367,455	)		546,891
Change in current assets and liabilities		(1,391,238	)		(417,882	)
Total cash flow from operations
Cash inflows (outflows)
Payments on note payable		(124,936	)		(173,479	)
Capital expenditures		(216,172	)		(58,719	)
Proceeds from sale of property and equipment		3,750,000			—
Total cash inflows (outflows)		3,408,892			(232,198	)
Total change in cash	$	2,017,654		$	(650,080	)

Going Concern. As described in Note (2), Significant Accounting Policies, in the “Notes to Condensed Consolidated Financial Statements” included in this report, our condensed consolidated financial statements contemplated that we would continue as a going concern. On August 3, 2011, we received proceeds of approximately $3.7 million in cash pursuant to the sale of a portion of our onshore facilities and pipeline assets. We anticipate that our current cash reserves will provide us with sufficient cash to fund our operations beyond the next twelve months. See Note (9), Disposition of Assets, in the “Notes to Condensed Consolidated Financial Statements” included in this report.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

Not Applicable.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Principal Financial and Accounting 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 September 30, 2011, our Chief Executive Officer and Principal Financial and 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 our Chief Executive Officer and Principal Financial and Accounting Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls over Financial Reporting

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

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time we are subject to various lawsuits, claims and administrative proceedings that arise out of the normal course of business. At present, we are involved in a lawsuit against the Lazarus Energy Holdings, LLC (“LEH”) to foreclose on a guaranty (the “Guaranty”) securing a $2.0 million loan, net of credited and recovered amounts (the “Loan”), that we made to Lazarus Louisiana Refinery II, LLC (“LLRII”).

Blue Dolphin v. LEH. On May 26, 2010, we filed a petition in the 129^th Judicial District, in the District Court of Harris County, State of Texas (the “Court”) alleging breach of contract and asserting our right to the unpaid principal balance and all accrued interest due and payable under the Loan. Although LEH filed a counter-claim alleging usurious interest based on a $500,000 consulting agreement made between the parties, in September 2010 we exercised our right to cure the alleged usury without having to admit guilt based on a statutory provision. In so doing, LLRII was credited $500,000 against the outstanding principal balance, and the matter proceeded without undue delay. In response, LEH filed an amended counter-claim further alleging breach of contract under the confidentiality agreement between the parties. By order dated February 7, 2011, the Court granted a partial summary judgment on liability under the promissory note and Guaranty in favor of Blue Dolphin and against LEH and LLRII. The Court, however, deferred a ruling on the damages and attorney’s fees to be awarded. Although the parties reached an agreement regarding the amount of attorneys’ fees to be awarded, and the defendants do not dispute the calculation of damages sought by Blue Dolphin, the defendants continue to contest Blue Dolphin’s entitlement to summary judgment. On February 25, 2011, we filed a motion for entry of the partial summary judgment. On March 28, 2011, our motion for entry of the partial summary judgment was heard before the Court. The Court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against LEH and LLRII on the promissory note and Guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement. On May 12, 2011, the parties entered into a Rule 11 Agreement in the interests of resolving the claims and disputes related to this matter. The parties have extended the deadline under the Rule 11 Agreement multiple times in an ongoing effort to re-establish a business arrangement that is beneficial to all involved parties.

We believe that the resolution of our current pending matter will not have a material adverse effect on our business, consolidated financial position, results of operations or cash flow.

See disclosures in Note (3), Loan Receivable, and Note (7), Commitments and Contingencies, in our Annual Report on Form 10-K for the period ended December 31, 2010.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in our Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Not applicable.

Item 5. Other Information

None.

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

Item 6.      Exhibits

(a) Exhibits:

     The following exhibits are filed herewith:

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.
32.1	Ivar Siem Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
32.2	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.
101	The following financial statements from the Company’s 10-Q for the quarter ended September 30. 2011, formatted in XBRL: (i) Condensed Consolidated Balance Sheets - September 30, 2011 (unaudited) and December 31, 2010, (ii) Condensed Consolidated Statements of Operations (Unaudited) - Three and Nine Months Ended September 30, 2011 and 2010, (iii) Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2011 and 2010, and (iv) Notes to Condensed Consolidated Financial Statements (Unaudited).

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BLUE DOLPHIN ENERGY COMPANY & SUBSIDIARIES

SIGNATURES

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

	By:	BLUE DOLPHIN ENERGY COMPANY
November 14, 2011	/s/ IVAR SIEM
	Ivar Siem
	Chairman, Chief Executive Officer, President, Assistant Treasurer and Secretary
November 14, 2011	/s/ T. SCOTT HOWARD
	T. Scott Howard
	Treasurer and Assistant Secretary (Principal Financial and Accounting Officer)

22

EX-31.1

Exhibit 31.1

I, Ivar Siem, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
4.	The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;
5.	The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2011

/s/ IVAR SIEM  

Ivar Siem 

Chairman, Chief Executive Officer, President,
Assistant Treasurer and Secretary 

EX-31.2

Exhibit 31.2

I, T. Scott Howard, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Blue Dolphin Energy Company (the “Registrant”).
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;
4.	The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:
	a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting;
5.	The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):
	a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and
	b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 14, 2011

/s/ T. SCOTT HOWARD  

T. Scott Howard 

Treasurer and Assistant Secretary
(Principal Financial and Accounting Officer) 

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Ivar Siem, Chairman, Chief Executive Officer, President, Assistant Treasurer and Secretary of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ IVAR SIEM  

Ivar Siem 

Chairman, Chief Executive Officer, President,
Assistant Treasurer and Secretary 

Date: November 14, 2011

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

     In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended September 30, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, T. Scott Howard, Treasurer and Assistant Secretary (Principal Accounting and Financial Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ T. SCOTT HOWARD  

T. Scott Howard 

Treasurer and Assistant Secretary
(Principal Financial and Accounting Officer) 

Date: November 14, 2011

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Stockholders' equity:
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	2,098,390	2,078,514
Common stock, shares outstanding	2,098,390	2,078,514

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Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenue from operations:
Pipeline operations	$ 219,006	$ 502,369	$ 829,011	$ 1,393,848
Oil and gas sales	301,417	237,940	1,004,148	278,161
Total revenue from operations	520,423	740,309	1,833,159	1,672,009
Cost of operations:
Pipeline operating expenses	532,931	243,531	999,297	855,842
Lease operating expenses	286,439	221,019	816,718	250,031
Depletion, depreciation and amortization	123,355	217,105	406,891	463,806
Recovery on previous allowance for doubtful loan receivable		(201,000)		(201,000)
General and administrative	273,567	286,288	1,056,203	1,084,537
Stock-based compensation	20,000	20,000	60,000	113,760
Accretion expense	32,805	30,563	98,884	88,678
Total cost of operations	1,269,097	817,506	3,437,993	2,655,654
Gain on sale of property and equipment	3,267,070		3,267,070
Income (Loss) from operations	2,518,396	(77,197)	1,662,236	(983,645)
Other income:
Interest and other income	5,138	8,115	15,276	18,872
Income (Loss) before income taxes	2,523,534	(69,082)	1,677,512	(964,773)
Income taxes
Net income (loss)	$ 2,523,534	$ (69,082)	$ 1,677,512	$ (964,773)
Income (Loss) per common share
Basic	$ 1.20	$ (0.04)	$ 0.80	$ (0.54)
Diluted	$ 1.20	$ (0.04)	$ 0.80	$ (0.54)
Weighted average number of common shares outstanding
Basic	2,094,438	1,967,278	2,088,581	1,793,365
Diluted	2,095,166	1,967,278	2,091,428	1,793,365

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Document and Entity Information (USD $) In Millions, except Share data	9 Months Ended
	Sep. 30, 2011	Nov. 03, 2011	Jun. 30, 2010
Document and Entity Information [Abstract]
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 2.7
Entity Common Stock, Shares Outstanding		2,098,390

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Loan Receivable

9 Months Ended

Sep. 30, 2011

Loan Receivable [Abstract]

Loan Receivable

(7) Loan Receivable

We recorded an allowance for doubtful loan receivable of $1.5 million at December 31, 2009. The loan receivable is associated with a $2.0 million loan, net of credited and recovered amounts (the “Loan”), made to Lazarus Louisiana Refinery II, LLC (“LLRII”) on July 31, 2009 and due on January 31, 2010. As of September 30, 2011, we continued to maintain a full allowance for the uncollected balance of the Loan.

In the second quarter of 2010, we began foreclosure proceedings in Louisiana against the collateral, as well as legal proceedings in Texas against the guaranty that secured the Loan. As a result of a foreclosure auction in Louisiana, we acquired a saltwater disposal well in the third quarter of 2010. Based on the asset’s appraised value, we recovered $201,000 of the allowance for doubtful loan receivable. Under the legal proceedings in Texas, we were granted a partial summary judgment on liability under the promissory note and guaranty in favor of Blue Dolphin. However, the court deferred a ruling on the damages and attorney’s fees to be awarded. On March 28, 2011, our motion for entry of the partial summary judgment was heard before the court. The court entered the partial summary judgment in the amount of $1.7 million in favor of Blue Dolphin and against Lazarus Energy Holdings (“LEH”) and LLRII on the promissory note and guaranty. The only claim that remains pending is the counter-claim alleging breach of contract under the confidentiality agreement. On May 12, 2011, the parties entered into a Rule 11 Agreement in the interests of resolving the claims and disputes related to this matter. The parties have extended the deadline under the Rule 11 Agreement multiple times in an ongoing effort to re-establish a business arrangement that is beneficial to all involved parties.

On July 13, 2011, we entered into a Purchase and Sale Agreement (the “PSA”) with LEH, LLRII, Lazarus Texas Refinery II, LLC, Lazarus Environmental, LLC, Lazarus Energy, LLC (“LE”) and Lazarus Energy Development, LLC whereby we will acquire 100% of the membership interest of LE, the primary asset of which is the Nixon Refinery near Nixon, Texas. Our purchase consideration is the issuance of eighty percent (80%) of our issued and outstanding common stock to LEH, which will represent a change in control of the Company. Closing of the transaction is subject to: (i) LEH obtaining funding of at least $3.7 million for startup of the Nixon Refinery and (ii) approval of the transaction by our stockholders. Upon consummation of the transaction, we have agreed to release LLRII of its obligation to pay the outstanding balance due under the Loan, as well as to release our claims against LLRII and LEH pursuant to the related lawsuit(s).

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Business Segment Information

9 Months Ended

Sep. 30, 2011

Business Segment Information [Abstract]

Business Segment Information

(3) Business Segment Information

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

Following is a reconciliation of our EBIT (by business segment) for the three months ended September 30, 2011, and at September 30, 2011:

	Three Months Ended September 30, 2011
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)			Total
Revenues	$	219,006	$	301,418		$	—		$	520,424
Operation cost(2)		641,004		399,174			105,565			1,145,743
Depletion, depreciation and amortization		90,254		32,445			656			123,355
Gain on sale of property and equipment		3,267,070		—			—			3,267,070
EBIT	$	2,754,818	$	(130,202	)	$	(106,220	)	$	2,518,396
Capital expenditures	$	8,105	$	130,704		$	53,561		$	192,370
Identifiable assets(3)	$	5,151,988	$	1,788,678		$	373,550		$	7,314,216

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of approximately $57,000
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Following is a reconciliation of our EBIT (by business segment) for the three months ended September 30, 2010, and at September 30, 2010:

	Three Months Ended September 30, 2010
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)		Total
Revenues	$	502,369	$	237,940		$	—	$	740,309
Operation cost(2)		333,715		335,987			131,699		801,401
Depletion, depreciation and amortization		105,043		110,881			1,181		217,105
Recovery on previous allowance for doubtful loan receivable		—		—			201,000		201,000
EBIT	$	63,611	$	(208,928	)	$	68,120	$	(77,197	)
Capital expenditures	$	—	$	1,135,802		$	201,000	$	1,336,802
Identifiable assets(3)	$	4,123,478	$	1,257,593		$	363,935	$	5,745,006

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of $0.4 million.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Following is a reconciliation of our EBIT (by business segment) for the nine months ended September 30, 2011, and at September 30, 2011:

	Nine Months Ended September 30, 2011
	Segment
			Oil and Gas
	Pipeline		Exploration &			Corporate &
	Transportation		Production			Other(1)			Total
Revenues	$	829,011	$	1,004,148		$	—		$	1,833,159
Operation cost(2)		1,446,655		1,255,077			329,370			3,031,102
Depletion, depreciation and amortization		292,745		111,627			2,519			406,891
Gain on sale of property and equipment		3,267,070		—			—			3,267,070
EBIT	$	2,356,681	$	(362,556	)	$	(331,889	)	$	1,662,236
Capital expenditures	$	8,105	$	154,506		$	53,561		$	216,172
Identifiable assets(3)	$	5,151,988	$	1,788,678		$	373,550		$	7,314,216

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of approximately $57,000.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

Following is a reconciliation of our EBIT (by business segment) for the nine months ended September 30, 2010, and at September 30, 2010:

	Nine Months Ended September 30, 2010
	Segment
				Oil and Gas
	Pipeline			Exploration &			Corporate &
	Transportation			Production			Other(1)			Total
Revenues	$	1,393,848		$	278,161		$	—		$	1,672,009
Operation cost(2)		1,657,109			395,032			340,707			2,392,848
Depletion, depreciation and amortization		315,128			144,729			3,949			463,806
Recovery on previous allowance for doubtful loan receivable		—			—			201,000			201,000
EBIT	$	(578,389	)	$	(261,600	)	$	(143,656	)	$	(983,645	)
Capital expenditures	$	—		$	1,135,802		$	201,000		$	1,336,802
Identifiable assets(3)	$	4,123,478		$	1,257,593		$	363,935		$	5,745,006

(1)	Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses). It also includes as identifiable assets corporate available cash of $0.4 million.
(2)	Allocable general and administrative costs are allocated based on revenue.
(3)	Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.

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Disposition of Assets

9 Months Ended

Sep. 30, 2011

Disposition of Assets [Abstract]

Disposition of Assets

(9) Disposition of Assets

Pursuant to an Asset Purchase Agreement, BDPL sold its eighty-three and one-third percent (83⅓%) undivided interest in the Buccaneer Pipeline to Sunoco for proceeds of approximately $3.7 million in cash. The transaction closed on August 3, 2011.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

(8) 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 condensed consolidated financial position, results of operations or cash flows.

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Organization

9 Months Ended

Sep. 30, 2011

Organization [Abstract]

Organization

(1) Organization

Company Summary

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

• Blue Dolphin Pipe Line Company (“BDPL”), 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.

Business Segments

We are engaged in two lines of business: (i) pipeline transportation services to producers/shippers, and (ii) oil and gas exploration and production. Our pipeline assets are located offshore and onshore in the Texas Gulf Coast area and our leasehold interests in properties are located in the U.S. Gulf of Mexico and the North Sumatra Basin in offshore Indonesia.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

(4) Asset Retirement Obligations

We have asset retirement obligations associated with the future abandonment of our pipelines and related facilities and our offshore oil and gas properties. The following table summarizes our asset retirement obligation transactions during the three months ended September 30, 2011:

Asset retirement obligations as of December 31, 2010	$	2,727,856
Liabilities incurred		—
Liabilities settled		(336,227	)
Accretion expense		98,884
Asset retirement obligations as of September 30, 2011		2,490,513
Less: current portion of asset retirement obligations		138,538
Asset retirement obligations long-term balance as of September 30, 2011	$	2,351,975

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

(5) Earnings Per Share

We apply the provisions of the ASC for computing earnings per share. The guidance 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. The guidance requires dual presentation of basic EPS and diluted EPS on the face of the condensed 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 quarter ended September 30, 2010, because their assumed exercise and conversion would have an anti-dilutive effect on the computation of diluted loss per share.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2011		2010			2011		2010
Net income (loss)	$	2,523,534	$	(69,082	)	$	1,677,512	$	(964,773	)
Basic
Weighted average number of shares of common stock outstanding		2,094,438		1,967,278			2,088,581		1,793,365
Per share amount	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)
Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		2,095,166		1,967,278			2,091,428		1,793,365
Per share amount	$	1.20	$	(0.04	)	$	0.80	$	(0.54	)

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Stock Options

9 Months Ended

Sep. 30, 2011

Stock Options [Abstract]

Stock Options

(6) Stock Options

We adopted the 2000 Stock Incentive Plan effective April 14, 2000, following approval by our stockholders. An amendment to the plan was approved by our stockholders in 2007. Under the plan, as amended (the “2000 Plan”), we are able to make awards of stock-based compensation. The 2000 Plan has expired and currently no shares may be issued under the plan. 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. 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 Board’s Compensation Committee.

Pursuant to the ASC guidance on accounting for stock based compensation, we estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no stock options granted in the nine months ended September 30, 2011, and the year ended December 31, 2010.

At September 30, 2011, there were a total of 30,390 shares of common stock reserved for issuance upon exercise of outstanding options under the 2000 Plan. A summary of the status of stock options granted to key employees, officers and directors, for the purchase of shares of common stock for the periods indicated, is as follows:

					Weighted Average
			Weighted Average		Remaining		Aggregate
	Shares		Exercise Price		Contractual Life		Intrinisic Value
Options outstanding at December 31, 2010		30,390	$	13.29
Options granted		—	$	—
Options exercised		—	$	—
Options expired or cancelled		—	$	—
Options outstanding at September 30, 2011		30,390	$	13.29		2.0	$	408
Options exercisable at September 30, 2011		30,390	$	13.29		2.0	$	408

The following table summarizes additional information about stock options outstanding at September 30, 2011:

	Options Outstanding					Options Exercisable
			Weighted Average					Weighted
			Remaining					Average
Range of Exercise	Number		Contractual Life	Weighted Average		Number		Exercise
Prices	Outstanding		(Years)	Exercise Price		Exercisable		Price
$2.45 to $5.60		10,118	1.6	$	3.06		10,118	$	3.06
$10.85 to $13.30		3,346	0.4	$	11.95		3,346	$	11.95
$19.67		16,926	2.7	$	19.67		16,926	$	19.67
		30,390					30,390

We recognized no compensation expense for vested stock options for the three and nine months ended September 30, 2011, compared to $0 and $53,760 for the three and nine months ended September 30, 2010, respectively. As of September 30, 2011, there was no unrecognized compensation cost related to non-vested stock options granted under the 2000 Plan.

We recognized $20,000 and $60,000 of expense related to the fair value issuance of restricted common stock to our independent directors for the three and nine months ended September 30, 2011, respectively.

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating Activities:
Net income (loss)	$ 1,677,512	$ (964,773)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depletion, depreciation and amortization	406,891	463,806
Gain on sale of property and equipment	(3,267,070)
Recovery on previous allowance for doubtful loan receivable		(201,000)
Accretion of asset retirement obligations	98,884	88,678
Stock-based compensation	60,000	113,760
Changes in operating assets and liabilities:
Accounts receivable	(118,359)	(62,357)
Prepaid expenses and other assets	129,908	171,695
Abandonment costs incurred	(336,227)	(38,996)
Accounts payable, accrued expenses and other current liabilities	(42,777)	11,305
Net cash used in operating activities	(1,391,238)	(417,882)
Investing Activities:
Purchases of property and equipment	(216,172)	(58,719)
Proceeds from sale of property and equipment	3,750,000
Net cash provided by (used in) investing activities	3,533,828	(58,719)
Financing Activities:
Payments on insurance finance note	(124,936)	(173,479)
Net cash used in financing activities	(124,936)	(173,479)
Net increase (decrease) in cash and cash equivalents	2,017,654	(650,080)
Cash and Cash Equivalents at Beginning of Period	625,854	1,016,483
Cash and Cash Equivalents at End of Period	2,643,508	366,403
Non-cash investing and financing activities
Purchase of property and equipment with company stock		685,714
Property and equipment acquired as partial settlement of loan receivable		201,000
Increase in asset retirement obligation and property and equipment		$ 391,369

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Significant Accounting Policies [Abstract]

Significant Accounting Policies

(2) Significant Accounting Policies

Principles of Consolidation

We have prepared our condensed consolidated financial statements without audit, in accordance with U.S. generally accepted accounting principles (“GAAP”) as codified by the Financial Accounting Standards Board (“FASB”) in its Accounting Standards Codification (“ASC”), pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). In the opinion of management, such condensed consolidated financial statements reflect all adjustments necessary to present fair condensed consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

Our accompanying unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our annual report on Form 10-K and Amendment No. 1 on Form 10-K/A for the fiscal year ended December 31, 2010 (“Annual Report”). The results of operations for the three and nine months ended September 30, 2011, are not necessarily indicative of the results of operations to be expected for the year ending December 31, 2011.

Accounting Estimates

We have made a number of estimates and assumptions related to the reporting of condensed consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these unaudited condensed consolidated financial statements in conformity with GAAP. This includes assessing the realization of an outstanding note receivable, the estimated useful life of pipeline assets, valuation of stock-based payments and reserve information, which affects the depletion calculation and the full-cost ceiling limitation. While we believe current estimates are reasonable and appropriate, actual results could differ from those estimated.

Going Concern

Our condensed consolidated financial statements, which have been prepared in accordance with GAAP, contemplated that we would continue as a going concern. As such, our condensed consolidated financial statements do not contain any adjustments that might result if we were unable to continue as a going concern.

On August 3, 2011, we received proceeds of approximately $3.7 million in cash pursuant to the sale of a portion of our onshore facilities and pipeline assets. We anticipate that our current cash reserves will provide us with sufficient cash to fund our operations beyond the next twelve months. See Note (9), Disposition of Assets, in the “Notes to Condensed Consolidated Financial Statements” included in this report.

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. We maintain cash and cash equivalent balances at one financial institution that is insured by the Federal Deposit Insurance Corporation (the “FDIC”). 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.

In October 2008, the FDIC amended its deposit insurance provisions to increase the basic limit amount from $100,000 to $250,000 per depositor. The coverage increase, which was intended to be temporary, was to revert back to $100,000 per depositor limit on December 31, 2009. However, in May 2009, the FDIC extended the coverage date through December 31, 2013. The temporary increase was made permanent in 2010 by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Accounts Receivable and 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 customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all aged accounts receivables for collectability and establish an allowance as necessary for individual customer balances. As of September 30, 2011 and December 31, 2010, there was no allowance recorded related to trade accounts receivable.

Oil and Gas Properties

We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration, and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. We use one cost center for domestic properties and one cost center for foreign properties. Amortization of such costs and estimated future development costs are 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.

Impairment of Oil and Gas Properties

We account for our oil and natural gas exploration and development activities using the full cost method of accounting. 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 a “ceiling,” which is determined based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. Our ceiling for the three and nine months ended September 30, 2011, was calculated using domestic prices of $94.50 per barrel of oil and $4.09 per MMbtu of gas and an international price of $107.59 per barrel of oil. Our ceiling for the three and nine months ended September 30, 2010, was calculated using domestic prices of $77.61 per barrel of oil and $4.42 per MMbtu of gas.

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 the ASC on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom. We did not have any impairment of our pipelines and facilities for the three and nine month periods ended September 30, 2011 and 2010. During the quarter ended September 30, 2011, BDPL sold its eighty-three and one-third percent (83⅓%) undivided interest in the Buccaneer Pipeline to Sunoco Partners Marketing and Terminals L.P. (“Sunoco”). BDPL still maintains its 83⅓% undivided interest in the Galveston Area Block 350 Pipeline, as well as an 83⅓% undivided interest in the Omega Pipeline.

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.

Stock-Based Compensation

Stock-based compensation is recognized in our condensed consolidated financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the condensed consolidated financial statements on a straight-line basis over the vesting period of the entire award.

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 September 30, 2011 and 2010 was not material.

Recognition of Pipeline Transportation Revenue

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

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Condensed Consolidated Balance Sheets (USD $)	Sep. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 2,643,508	$ 625,854
Accounts receivable, net of allowance for doubtful accounts	716,750	598,391
Prepaid expenses and other current assets	83,163	213,071
Loan receivable, net of allowance for loan receivable	0	0
Total current assets	3,443,421	1,437,316
Property and equipment, at cost:
Oil and gas properties (full-cost method)	2,377,041	2,222,535
Pipelines	4,342,480	4,659,686
Onshore separation and handling facilities	1,344,455	1,919,402
Land	473,225	860,275
Other property and equipment	557,374	503,813
Total property and equipment, at cost	9,094,575	10,165,711
Less: Accumulated depletion, depreciation and amortization	5,233,243	5,630,730
Total property and equipment, net	3,861,332	4,534,981
Loan receivable, net of allowance for loan receivable	0	0
Other assets	9,463	9,463
Total assets	7,314,216	5,981,760
Current liabilities:
Accounts payable	463,094	543,327
Note payable - insurance	0	124,936
Asset retirement obligations, current portion	138,538	192,470
Accrued expenses and other current liabilities	39,598	2,142
Total current liabilities	641,230	862,875
Long-term liabilities:
Asset retirement obligations, net of current portion	2,351,975	2,535,386
Total liabilities	2,993,205	3,398,261
Commitments and contingencies
Stockholders' equity:
Common stock ($0.01 par value, 100,000,000 shares authorized, 2,098,390 and 2,078,514 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively)	20,984	20,785
Additional paid-in capital	33,753,061	33,693,260
Accumulated deficit	(29,453,034)	(31,130,546)
Total stockholders' equity	4,321,011	2,583,499
Total liabilities and stockholders' equity	$ 7,314,216	$ 5,981,760