10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended:  March 31, 2016

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

For the transition period from _____________ to_____________

Commission File Number: 0-15905

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

(713) 568-4725

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 x No  o

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

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

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

Yes  o   No x

Number of shares of common stock, par value $0.01 per share outstanding as of May 16, 2016:  10,458,400

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	5
ITEM 1.	FINANCIAL STATEMENTS	5
	Consolidated Balance Sheets (Unaudited)	5
	Consolidated Statements of Operations (Unaudited)	6
	Consolidated Statements of Cash Flows (Unaudited)	7
	Notes to Consolidated Financial Statements	8
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
ITEM 4.	CONTROLS AND PROCEDURES	45
PART II.	OTHER INFORMATION	45
ITEM 1.	LEGAL PROCEEDINGS	45
ITEM 1A.	RISK FACTORS	45
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	46
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	46
ITEM 4.	MINE SAFETY DISCLOSURES	46
ITEM 5.	OTHER INFORMATION	46
ITEM 6.	EXHIBITS	46
SIGNATURES		47

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

GLOSSARY OF SELECTED OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms used in our Quarterly Report for the quarterly period ended March 31, 2016 (the “Quarterly Report”), which are commonly used in the oil and gas industry:

Atmospheric gas oil (“AGO”). The heaviest product boiled by a crude distillation unit operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. Blended AGO usually serves as the premium quality component used to lift lesser streams to the standards of saleable furnace oil or diesel engine fuel. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock. Barrel (“bbl”). One stock tank bbl, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons. Blending. The physical mixture of a number of different liquid hydrocarbons to produce a finished product with certain desired characteristics. Products can be blended in-line through a manifold system, or batch blended in tanks and vessels. In-line blending of gasoline, distillates, jet fuel and kerosene is accomplished by injecting proportionate amounts of each component into the main stream where turbulence promotes thorough mixing. Additives, including octane enhancers, metal deactivators, anti-oxidants, anti-knock agents, gum and rust inhibitors, and detergents, are added during and/or after blending to result in specifically desired properties not inherent in hydrocarbons. Barrels per Day (“bpd”). A measure of oil output representing the number of bbls of oil produced in a single operating day. Capacity utilization rate. A percentage measure that indicates the amount of available capacity that is being used at a facility. Complexity. A numerical score that denotes, for a given refinery, the extent, capability, and capital intensity of the refining processes downstream of the crude oil distillation unit. The higher a refinery’s complexity, the greater the refinery’s capital investment and number of operating units used to separate feedstock into fractions, improve their quality, and increase the production of higher-valued products. Refinery complexities range from the relatively simple crude oil distillation unit (“topping unit”), which has a complexity of 1.0, to the more complex deep conversion (“coking”) refineries, which have a complexity of 12.0. Condensate. Liquid hydrocarbons that are produced in conjunction with natural gas. Condensate is chemically more complex than LPG. Although condensate is sometimes similar to crude oil, it is usually lighter. Crude oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. Crude oil quality is measured in terms of density (light to heavy) and sulfur content (sweet to sour). Crude oil must be broken down into its various components by distillation before these chemicals and compounds can be used as fuels or converted to more valuable products. Depropanizer unit. A distillation column that is used to isolate propane from a mixture containing butane and other heavy components. Distillates. The result of crude distillation and therefore any refined oil product. Distillate is more commonly used as an abbreviated form of middle distillate. There are mainly four (4) types of distillates: (i) very light oils or light distillates (such as our LPG mix and naphtha), (ii) light oils or middle distillates (such as our jet fuel), (iii) medium oils, and (iv) heavy oils (such as diesel and our heavy oil-based mud blendstock (“HOBM”), reduced crude, and AGO). Distillation. The first step in the refining process whereby crude oil and condensate is heated at atmospheric pressure in the base of a distillation tower. As the temperature increases, the various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower according to their densities, from lightest to heaviest. They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities. Lighter products produced in this process can be further refined in a catalytic cracking unit or reforming unit. Heavier products, which cannot be vaporized and separated in this process, can be further distilled in a vacuum distillation unit or coker.
Distillation tower. A tall column-like vessel in which crude oil and condensate is heated and its vaporized components distilled by means of distillation trays.
Feedstocks. Crude oil and other hydrocarbons, such as condensate and/or intermediate products, that are used as basic input materials in a refining process. Feedstocks are transformed into one or more finished products.
Finished petroleum products. Materials or products which have received the final increments of value through processing operations, and which are being held in inventory for delivery, sale, or use.
Intermediate petroleum products. A petroleum product that might require further processing before it is saleable to the ultimate consumer. This further processing might be done by the producer or by another processor. Thus, an intermediate petroleum product might be a final product for one company and an input for another company that will process it further.
Jet fuel. A high-quality kerosene product primarily used in aviation. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.
Kerosene. A middle distillate fraction of crude oil that is produced at higher temperatures than naphtha and lower temperatures than gas oil. It is usually used as jet turbine fuel and sometimes for domestic cooking, heating, and lighting.
Leasehold interest. The interest of a lessee under an oil and gas lease.
Light crude. A liquid petroleum that has a low density and flows freely at room temperature. It has a low viscosity, low specific gravity, and a high American Petroleum Institute gravity due to the presence of a high proportion of light hydrocarbon fractions.
Liquefied petroleum gas (“LPG”). Manufactured during the refining of crude oil and condensate; burns relatively cleanly with no soot and very few sulfur emissions.
MMcf.One million cubic feet; a measurement of gas volume only.
Naphtha. A refined or partly refined light distillate fraction of crude oil. Blended further or mixed with other materials it can make high-grade motor gasoline or jet fuel. It is also a generic term applied to the lightest and most volatile petroleum fractions.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil. Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of LPGs. The others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. See definition of LPG. Refined petroleum products. Refined petroleum products are derived from crude oil and condensate that have been processed through various refining methods. The resulting products include gasoline, home heating oil, jet fuel, diesel, lubricants and the raw materials for fertilizer, chemicals, and pharmaceuticals. Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil and condensate is separated and transformed into petroleum products. Sour crude. Crude oil containing sulfur content of more than 0.5%. Stabilizer unit. A distillation column intended to remove the lighter boiling compounds, such as butane or propane, from a product. Sweet crude. Crude oil containing sulfur content of less than 0.5%. Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal, or natural gas. Also produced as a by-product of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized according to their sulfur content, with lower sulfur fuels usually selling at a higher, premium price and higher sulfur fuels selling at a lower, or discounted, price.
Topping unit. A type of petroleum refinery that engages in only the first step of the refining process -- crude distillation. A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0.
Throughput. The volume processed through a unit or a refinery or transported through a pipeline.
Turnaround. Scheduled large-scale maintenance activity wherein an entire process unit is taken offline for a week or more for comprehensive revamp and renewal.
Yield. The percentage of refined petroleum products that is produced from crude oil and other feedstocks.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	560,273		$	1,853,875
Restricted cash		3,013,035			3,175,299
Accounts receivable, net		3,326,561			5,457,245
Prepaid expenses and other current assets		1,357,672			939,690
Deposits		229,933			395,414
Inventory		14,850,967			7,808,318
Deferred tax assets, current portion, net		4,845,465			3,486,746
Total current assets		28,183,906			23,116,587
Total property and equipment, net		53,147,209			48,841,812
Restricted cash, noncurrent		12,551,748			15,616,478
Surety bonds		1,022,000			1,022,000
Trade name		303,346			303,346
Deferred tax assets, net		-			120,491
Total long-term assets		67,024,303			65,904,127
TOTAL ASSETS	$	95,208,209		$	89,020,714
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	24,696,745		$	14,882,714
Accounts payable, related party		408,556			300,000
Asset retirement obligations, current portion		38,644			38,644
Accrued expenses and other current liabilities		1,719,195			2,990,891
Interest payable, current portion		87,558			81,467
Long-term debt less unamortized debt issue costs, current portion		32,942,090			1,934,932
Total current liabilities		59,892,788			20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion		1,939,363			1,947,220
Deferred revenues and expenses		114,661			125,085
Long-term debt less unamortized debt issue costs, net of current portion		1,392,787			32,846,254
Long-term interest payable, net of current portion		1,534,661			1,482,801
Deferred tax liabilities, net		72,327			-
Total long-term liabilities		5,053,799			36,401,360
TOTAL LIABILITIES		64,946,587			56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,608,400 and
10,603,802 shares issued at March 31, 2016 and December 31, 2015, respectively)		106,084			106,038
Additional paid-in capital		36,758,691			36,738,737
Accumulated deficit		(5,803,153	)		(3,654,069	)
Treasury stock, 150,000 shares at cost		(800,000	)		(800,000	)
Total stockholders' equity		30,261,622			32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	95,208,209		$	89,020,714

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Consolidated Statements of Operations (Unaudited)

	Three Monthe Ended March 31,
	2016			2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$	31,193,137		$	61,067,062
Tank rental revenue		291,487			286,892
Pipeline operations		27,652			38,395
Total revenue from operations		31,512,276			61,392,349
COST OF OPERATIONS
Cost of refined products sold		30,993,477			49,387,449
Refinery operating expenses		3,437,015			2,880,971
Joint Marketing Agreement profit share		(671,092	)		2,438,637
Pipeline operating expenses		79,290			46,596
Lease operating expenses		14,652			7,316
General and administrative expenses		357,004			345,884
Depletion, depreciation and amortization		440,453			399,231
Recovery of bad debt		(139,868	)		-
Accretion expense		28,186			53,215
Total cost of operations		34,539,117			55,559,299
Income (loss) from operations		(3,026,841	)		5,833,050
OTHER INCOME (EXPENSE)
Easement, interest and other income		131,763			66,007
Interest and other expense		(419,907	)		(208,075	)
Total other expense		(288,144	)		(142,068	)
Income (loss) before income taxes		(3,314,985	)		5,690,982
Income tax benefit (expense)		1,165,901			(1,989,618	)
Net income (loss)	$	(2,149,084	)	$	3,701,364
Income (loss) per common share:
Basic	$	(0.21	)	$	0.35
Diluted	$	(0.21	)	$	0.35
Weighted average number of common shares outstanding:
Basic		10,457,794			10,449,444
Diluted		10,457,794			10,449,444

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
	2016			2015
OPERATING ACTIVITIES
Net income (loss)	$	(2,149,084	)	$	3,701,364
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization		440,453			399,231
Unrealized loss (gain) on derivatives		(1,374,040	)		548,190
Deferred tax expense (benefit)		(1,165,901	)		1,807,484
Amortization of debt issue costs		32,122			8,450
Accretion expense		28,186			53,215
Common stock issued for services		20,000			-
Recovery of bad debt		(139,868	)		-
Changes in operating assets and liabilities
Accounts receivable		2,270,552			(1,536,092	)
Prepaid expenses and other current assets		772,658			650,694
Deposits and other assets		165,481			(80,513	)
Inventory		(7,042,649	)		129,941
Accounts payable, accrued expenses and other liabilities		7,631,014			(2,046,849	)
Accounts payable, related party		108,556			(1,054,523	)
Net cash provided by (used in) operating activities		(402,520	)		2,580,592
INVESTING ACTIVITIES
Capital expenditures		(3,639,645	)		(1,291,915	)
Change in restricted cash for investing activities		3,064,730			-
Net cash used in investing activities		(574,915	)		(1,291,915	)
FINANCING ACTIVITIES
Payments on long-term debt		(478,431	)		(300,106	)
Change in restricted cash for financing activities		162,264			(2,598	)
Net cash used in financing activities		(316,167	)		(302,704	)
Net increase (decrease) in cash and cash equivalents		(1,293,602	)		985,973
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,853,875			1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	560,273		$	2,279,206
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	$	1,106,205		$	-
Interest paid	$	668,343		$	165,513
Income taxes paid	$	-		$	-

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements
(1)	Organization

Nature of Operations.  We are primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (4) Business Segment Information” of this Quarterly Report for further discussion of our business segments.

Structure and Management.We were formed as a Delaware corporation in 1986.  We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the “Operating Agreement”).  Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer and President of Blue Dolphin, as well as a majority owner of LEH.   See “Note (8) Accounts Payable, Related Party,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” of this Quarterly Report for additional disclosures related to the Operating Agreement, Jonathan Carroll, and LEH.

Our operations are conducted through the following operating subsidiaries:

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

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

· Blue Dolphin Pipe Line Company, a Delaware corporation;

· Blue Dolphin Petroleum Company, a Delaware corporation; and

· Blue Dolphin Services Co., a Texas corporation.

See "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Owned and Leased Assets” in our Annual Report for the fiscal year ended December 31, 2015 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding our operating subsidiaries.

Operating Risks.  We had cash and cash equivalents of $560,273 and $1,853,875 at March 31, 2016 and December 31, 2015, respectively. We currently rely on our profit share under the Joint Marketing Agreement and LEH to fund our working capital requirements.  During months in which we receive no profit share under the Joint Marketing Agreement, LEH may, but is not required to, fund our working capital requirements.  There can be no assurances that LEH will continue to fund our working capital requirements.

As of March 31, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign Bank, a Texas state bank (“Sovereign”). We are currently making our scheduled monthly payments in accordance with the terms and conditions of the loan agreements.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to Sovereign, our long-term debt, and financial covenant violations.

In addition to the Joint Marketing Agreement, we are party to a variety of contracts and agreements with Genesis Energy, LLC “(Genesis”) and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice.  These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain these relationships or our relationships are not on good terms, it could have a material adverse effect on our operations, liquidity and financial condition. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to Genesis, the Joint Marketing Agreement, and the Crude Supply Agreement.

We believe that our cash flows from operations, existing cash and cash equivalents, and proceeds from credit facilities will be sufficient to support our operations and capital expenditures for the next 12 to 18 months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and the financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

(2) Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation.  In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

The consolidated balance sheet at December 31, 2015 has been derived from the audited financial statements at that date.  The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report.  Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016, or for any other period.

(3) Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management who is responsible for its integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.

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

Cash and Cash Equivalents.Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents totaled $560,273 and $1,853,875 at March 31, 2016 and December 31, 2015, respectively.

Restricted Cash.Restricted cash, current totaled $3,013,035 and $3,175,299 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, noncurrent totaled $12,551,748 and $15,616,478 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, current primarily represents: (i) a construction contingency account under which Sovereign will fund contingencies and (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement.  Restricted cash, noncurrent represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to loan agreements with Sovereign.

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 on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary.  Allowance for doubtful accounts totaled $0 and $139,868 at March 31, 2016 and December 31, 2015, respectively.

Inventory.The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals.  Inventory reflected for crude oil and condensate is nominal and represents line fill.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.  If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold.  See “Note (6) Inventory” of this Quarterly Report for additional disclosures related to our inventory.

Derivatives.We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy.  Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations.  Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.

See “Note (17) Fair Value Measurement” and “Note (18) Inventory Risk Management” of this Quarterly Report for additional disclosures related to derivatives.

Property and Equipment.

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement.  Management expects to continue making improvements to the Nixon Facility based on technological advances.

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets at March 31, 2016 or December 31, 2015.

Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment.  Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our oil and gas properties had no production during the three months ended March 31, 2016 and 2015.  All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired at December 31, 2012.

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

See “Note (7) Property, Plant and Equipment, Net” of this Quarterly Report for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.

Intangibles – Other. We have an intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015.

10

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Revenue Recognition.

Refined Petroleum Products Revenue. We sell jet fuel in nearby markets, and our intermediate products, including LPG, naphtha, HOBM, and AGO, to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

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

Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.

Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.

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

Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the “Purchase Agreement”) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of retiring certain of the assets. See “Part I, Business -- Governmental Regulation -- Offshore Safety and Environmental Oversight – Decommissioning Requirements” of our Annual Report for a discussion related to supplemental pipeline bonds.

Income Taxes. We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.

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

See “Note (15) Income Taxes” of this Quarterly Report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized.  Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

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

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

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

See “Note (11) Asset Retirement Obligations” of this Quarterly Report for additional information related to our AROs.

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

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases.  See “Note (16) Earnings Per Share” for additional information related to EPS.

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

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Treasury Stock. We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets.  See “Note (12) Treasury Stock” of this Quarterly Report for additional disclosures related to treasury stock.

New Accounting Pronouncement.  In April 2015, FASB issued ASU 2015-03, Imputation of Interest (Topic 835):  Simplifying the Presentation of Debt Issuance Costs.  This guidance requires debt issue costs to be presented as an offset to their related debt.  Effective January 1, 2015, we adopted this accounting pronouncement.  Accordingly, our consolidated balance sheets at March 31, 2016 and December 31, 2015 as reflected within this Quarterly Report have been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.

New Pronouncements Issued But Not Yet Effective. FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content.  The following are recently issued, but not yet effective, accounting standards that may have an effect on our consolidated financial position, results of operations, or cash flows:

ASU 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02.This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent.  Current GAAP requires deferred tax liabilities and assets to be separated into current and noncurrent.  ASU 2015-17 is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period, and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented.  We anticipate utilizing the majority of our current deferred tax assets prior to the effective date of ASU 2015-17.  We do not anticipate adoption of this guidance to have a material effect on our consolidated balance sheets.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market.  Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin.  Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value.  Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards.  For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.  ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern for a one year period subsequent to the date of the financial statements.  An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In May 2014, FASB issued ASU 2014-09, which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year.The effective date for public business entities is annual reporting periods beginning after December 15, 2017.  Public business entities would apply the new revenue standard to interim reporting periods after December 15, 2017.  As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods.  This represents a one-year deferral from the original effective date.  The new effective date guidance allows early adoption for all entities as of the original effective date (December 15, 2016). In March 2016, FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), which clarifies the implementation guidance on principal versus agent considerations. When another party, along with the entity, is involved in providing a good or a service to a customer, the entity must determine whether the nature of its promise is to provide that good or service to the customer (e.g., entity as principal) or to arrange for the good or service to be provided to the customer by the other party (e.g., entity as agent).  Such determination is based upon whether the entity controls the good or the service before it is transferred to the customer.  We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, and ASU 2016-08, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.

Other new pronouncements issued but not effective until after March 31, 2016 are not expected to have a material impact on our financial position, results of operations or liquidity.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

(4) Business Segment Information

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

Business segment information for the three months ended March 31, 2016 and 2015 (and at March 31, 2016 and 2015), was as follows:

	Three Months Ended March 31, 2016												Three Months Ended March 31, 2015
	Segment												Segment
	Refinery Operations			Pipeline Transportation			Corporate & Other			Total			Refinery Operations			Pipeline Transportation			Corporate & Other			Total
Revenue from operations	$	31,484,624		$	27,652		$	-		$	31,512,276		$	61,353,954		$	38,395		$	-		$	61,392,349
Less: cost of operations(1)		(34,422,853	)		(122,128	)		(224,775	)		(34,769,756	)		(52,259,470	)		(53,912	)		(408,048	)		(52,721,430	)
Other non-interest income(2)		-			130,665			-			130,665			-			62,500			-			62,500
Adjusted EBITDA		(2,938,229	)		36,189			(224,775	)		(3,126,815	)		9,094,484			46,983			(408,048	)		8,733,419
Less:  JMA Profit Share(3)		671,092			-			-			671,092			(2,438,637	)		-			-			(2,438,637	)
EBITDA	$	(2,267,137	)	$	36,189		$	(224,775	)				$	6,655,847		$	46,983		$	(408,048	)
Depletion, depreciation and amortization											(440,453	)											(399,231	)
Interest expense, net											(418,809	)											(204,569	)
Income (loss) before income taxes											(3,314,985	)											5,690,982
Income tax benefit (expense)											1,165,901												(1,989,618	)
Net income (loss)										$	(2,149,084	)										$	3,701,364
Capital expenditures	$	3,639,645		$	-		$	-		$	3,639,645		$	1,291,915		$	-		$	-		$	1,291,915
Identifiable assets	$	87,970,266		$	2,026,778		$	5,211,165		$	95,208,209		$	53,361,470		$	2,923,368		$	4,355,252		$	60,640,090

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue.  See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” of this Quarterly Report for further discussion related to FLNG.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

(5) Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
Unrealized hedging gains	$	1,190,640	$	-
Prepaid insurance		155,782		315,120
Prepaid listing fees		11,250		-
Prepaid related party operating expenses		-		624,570
	$	1,357,672	$	939,690

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

(6) Inventory

Inventory for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
HOBM	$	8,327,943	$	5,007,576
Jet fuel		5,547,597		2,045,784
Naphtha		427,496		309,850
AGO		408,152		278,278
Chemicals		101,063		122,777
Crude oil and condensate		19,041		19,041
Propane		11,212		17,860
LPG mix		8,463		7,152
	$	14,850,967	$	7,808,318

Product mix and inventory levels may fluctuate from one period to the next to capture market opportunities.  At March 31, 2016, our diesel and jet fuel inventory increased intentionally compared to December 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

(7) Property, Plant and Equipment, Net

Property, plant and equipment, net, for the periods indicated consisted of the following:

	March 31,			December 31,
	2016			2015
Refinery and facilities	$	43,046,528		$	40,195,928
Pipelines and facilities		2,127,207			2,127,207
Onshore separation and handling facilities		325,435			325,435
Land		602,938			602,938
Other property and equipment		652,795			644,795
		46,754,903			43,896,303
Less:  Accumulated depletion, depreciation, and amortization		(6,674,613	)		(6,234,161	)
		40,080,290			37,662,142
Construction in progress		13,066,919			11,179,670
	$	53,147,209		$	48,841,812

We capitalize interest cost incurred on funds used to construct property, plant, and equipment.  The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s useful life.  Interest cost capitalized was $954,134 and $556,032 at March 31, 2016 and December 31, 2015, respectively.

(8) Accounts Payable, Related Party

Accounts payable, related party totaled $408,556 and $300,000 at March 31, 2016 and December 31, 2015, respectively.  Accounts payable, related party consisted of reimbursements and fees under the Operating Agreement, off-site storage tank leasing expense, and guaranty fee expense related to certain of our long-term debt.

Short-Term Tank Lease Agreement.  We utilize a short-term tank lease agreement with Ingleside Crude, LLC (“Ingleside”) to meet periodic additional storage needs.  The Tank Lease Agreement had an initial term of 30 days and automatically renews for 30 day periods. The parties may terminate the Tank Lease Agreement upon 30 days written notice. Ingleside is a related party of LEH and Jonathan Carroll.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

At March 31, 2016 and December 31, 2015, accounts payable, related party to Ingleside totaled $172,389 and $300,000, respectively.  For the three months ended March 31, 2016 and 2015, fees to Ingleside totaled $275,000 (approximately $0.23 per bbl of throughput) and $0, respectively, and were reflected as refinery operating expenses in our consolidated statements of operations.

Operating Agreement.  LEH manages and operates all of our properties pursuant to the Operating Agreement.  LEH, our controlling shareholder, owns approximately 81% of our Common Stock.  Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party.

For services rendered, LEH receives reimbursements and fees as follows:

· Reimbursements. For management and operation of all properties excluding the Nixon Facility, LEH is reimbursed at cost for all reasonable expenses incurred while performing the services.  Unsettled reimbursements to LEH are reflected within prepaid expenses and other current assets or accounts payable, related party in our consolidated balance sheets.

At March 31, 2016, accounts payable, related party to LEH totaled $77,836.  At December 31, 2015, prepaid related party operating expenses to LEH totaled $624,570.  See “Note (5) Prepaid Expenses and Other Current Assets” of this Quarterly Report for additional disclosures with respect to related party expenses.

· Fees. For management and operation of the Nixon Facility, LEH receives fees: (i) in the form of weekly payments from GEL TEX Marketing, LLC (“GEL”) not to exceed $750,000 per month, (ii) $0.25 for each bbl processed at the Nixon Facility up to a maximum quantity of 10,000 bbls per day determined on a monthly basis, and (iii) $2.50 for each bbl processed at the Nixon Facility in excess of 10,000 bbls per day determined on a monthly basis.  Amounts expensed as fees are reflected as refinery operating expenses in our consolidated statements of operations.

For the three months ended March 31, 2016 and 2015, fees to LEH totaled $3,162,017 (approximately $2.67 per bbl of throughput) and $2,880,971 (approximately $2.71 per bbl of throughput), respectively, and were reflected as refinery operating expenses in our consolidated statements of income.

Guaranty Fees Agreements.  As a condition of certain of our long-term debt, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loans.  For his personal guarantee, Jonathan Carroll receives fees pursuant to Guaranty Fee Agreements. At March 31, 2016 and December 31, 2015, accounts payable, related party to Jonathan Carroll totaled $158,331 and $0, respectively.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for further discussion related to the Guaranty Fee Agreements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

(9) Long-Term Debt, Net

Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, consisted of the following for the periods indicated:

	March 31, 2016								December 31, 2015
			Debt Issue			Long-Term					Debt Issue			Long-Term
	Principal		Costs			Debt, Net			Principal		Costs			Debt, Net
First Term Loan Due 2034		24,464,586		(1,601,787	)		22,862,799			24,643,081		(1,623,810	)		23,019,271
Second Term Loan Due 2034		9,926,704		(757,572	)		9,169,132			10,000,000		(767,672	)		9,232,328
Notre Dame Debt		1,300,000		-			1,300,000			1,300,000		-			1,300,000
Term Loan Due 2017		739,974		-			739,974			924,969		-			924,969
Capital Leases		262,972		-			262,972			304,618		-			304,618
	$	36,694,236	$	(2,359,359	)	$	34,334,877		$	37,172,668	$	(2,391,482	)	$	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion							(32,942,090	)							(1,934,932	)
						$	1,392,787							$	32,846,254

Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) consisted of the following for the periods indicated:

	March 31,			December 31,
	2016			2015
Notre Dame Debt		1,534,661			1,482,801
First Term Loan Due 2034		45,894			34,883
Second Term Loan Due 2034		34,630			39,193
Term Loan Due 2017		4,779			4,779
Capital Leases		2,255			2,612
	$	1,622,219		$	1,564,268
Less:  Interest payable, current portion		(87,558	)		(81,467	)
	$	1,534,661		$	1,482,801

First Term Loan Due 2034. LE entered into a Loan and Security Agreementwith Sovereign in June 2015, as administrative agent and lender pursuant to a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”).  The First Term Loan Due 2034 matures in June 2034, has current monthly payments of principal and interest of $188,409, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash and restricted cash, noncurrent in our consolidated balance sheets.

As of March 31, 2016, LE was in violation of the debt service coverage ratio and the current ratio financial covenants under the First Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 has been classified within the current portion of long-term debt on our consolidated balance sheets.  See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the First Term Loan Due 2034.

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LE entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the First Term Loan Due 2034.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $122,633 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.  LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed to American First National Bank under the Refinery Note.  Remaining proceeds are being used primarily to construct new petroleum storage tanks. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a $1.0 million payment reserve account held by Sovereign, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll.  The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.

Second Term Loan Due 2034. LRM entered into a Loan and Security Agreementwith Sovereign in December 2015, as administrative agent and lender pursuant to a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”).  The Second Term Loan Due 2034 matures in December 2034, has current monthly payments of principal and interest of $74,111, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash and restricted cash, noncurrent in our consolidated balance sheets.

As of March 31, 2016, LRM was in violation of the debt service coverage ratio and the current ratio financial covenants under the Second Term Loan Due 2034. Accordingly, the Second Term Loan Due 2034 has been classified within the current portion of long-term debt on our consolidated balance sheets.  See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the Second Term Loan Due 2034.

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan P. Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,747 and $0, respectively.  Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.   LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

Proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan to Sovereign in the amount of $3.0 million.  Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the Nixon Facility and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of Tanks 62, 63, and 80, with respect to which Sovereign will have a second priority lien in such leases subordinate to a prior lien granted by LRM to Sovereign to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents.  The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.

Notre Dame Debt. LE entered into a loan with Notre Dame Investors, Inc. as evidenced by a Promissory Note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt matures in January 2018, and accrues interest at a rate of 16.00%.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt. Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Sovereign as holder of the First Term Loan Due 2034.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for additional disclosures related to the Genesis Agreements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Term Loan Due 2017. LRM entered into a Loan and Security Agreement with Sovereign in May 2014, for a term loan facility in the principal amount of $2.0 million (the “Term Loan Due 2017”).  The Term Loan Due 2017 was amended in March 2015, pursuant to a Loan Modification Agreement (the “March Loan Modification Agreement”).  Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due date was extended to March 2017.  Pursuant to the March Loan Modification Agreement, the monthly payment due under the Term Loan Due 2017 is $61,665 plus interest.

As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Term Loan Due 2017.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $4,008 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units.  The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and certain assets of LEH.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

Capital Leases. LRM entered into a 36 month build-to-suit capital lease in August 2014 for the purchase of new boiler equipment for the Nixon Facility.  The equipment, which was delivered in December 2014, was added to construction in progress.  Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease, which requires a quarterly payment in the amount of $44,258, is guaranteed by Blue Dolphin.

A summary of equipment held under long-term capital leases for the periods indicated follows:

	March 31,		December 31,
	2016		2015
Boiler equipment	$	538,598	$	538,598
Less:  accumulated depreciation		-		-
	$	538,598	$	538,598

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20

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

(10) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities for the periods indicated consisted of the following: 

	March 31,		December 31,
	2016		2015
Excise and income taxes payable	$	1,080,083	$	1,290,101
Unearned revenue		315,000		781,859
Other payable		131,115		157,714
Board of director fees payable		98,929		86,429
Insurance		64,390		103,024
Property taxes		29,678		-
Genesis JMA Profit Share payable		-		388,364
Unrealized hedging loss		-		183,400
	$	1,719,195	$	2,990,891

(11) Asset Retirement Obligations

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

Pipelines and Facilities and Oil and Gas Properties.  We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

Changes to our ARO liability for the periods indicated were as follows:

	March 31,			December 31,
	2016			2015
Asset retirement obligations, at the beginning of the period	$	1,985,864		$	1,866,770
New asset retirement obligations and adjustments		-			49
Liabilities settled		(36,043	)		(92,330	)
Accretion expense		28,186			211,375
		1,978,007			1,985,864
Less:  asset retirement obligations, current portion		(38,644	)		(38,644	)
Long-term asset retirement obligations, at the end of the period	$	1,939,363		$	1,947,220

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability and are reflected in our consolidated balance sheets.  At March 31, 2016 and December 31, 2015, we recognized $36,043 and $92,330, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability and are reflected in our consolidated statements of operations.  For the three months ended March 31, 2016 and 2015, we recognized $0 in abandonment expense.

(12) Treasury Stock

At March 31, 2016 and December 31, 2015, we had 150,000 shares of treasury stock.

(13) Concentration of Risk

Bank Accounts. Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the U.S., the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor.  We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $15,507,858 and $19,594,883 at March 31, 2016 and December 31, 2015, respectively.

Key Supplier. Under the Crude Oil and Supply Throughput Services Agreement dated in August 2011 (the “Crude Supply Agreement”), GEL is our exclusive supplier of crude oil and condensate.  We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL.  The initial term was to expire in August 2014.  However, in October 2013, we entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam Services, Inc. (“Milam”) (the “October 2013 Letter Agreement”), effective in October 2013.  In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice.

Significant Customers. We routinely assess the financial strength of our customers and have not experienced significant write-downs in our accounts receivable balances.  As a result, we believe that our accounts receivable credit risk exposure is limited.  For the three months ended March 31, 2016, we had 5 customers that accounted for approximately 75.4% of our refined petroleum products sales.  These 5 customers represented approximately $2.3 million in accounts receivable at March 31, 2016.  For the three months ended March 31, 2015, we had 3 customers that accounted for approximately 67% of our refined petroleum products sales.  These 3 customers represented approximately $4.1 million in accounts receivable at March 31, 2015.

Refined Petroleum Product Sales. All of our refined petroleum products are currently sold in the U.S. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016				2015
LPG mix	$	250,547	0.8	%	$	57,308	0.0	%
Naphtha		9,025,521	28.9	%		13,416,199	22.0	%
Jet fuel		8,506,313	27.3	%		16,519,503	27.1	%
HOBM		3,163,495	10.1	%		17,409,079	28.5	%
Reduced Crude		3,245,807	10.4	%		-	0.0	%
AGO		7,001,454	22.5	%		13,664,973	22.4	%
	$	31,193,137	100.0	%	$	61,067,062	100.0	%

For the three months ended March 31, 2016 we sold less bbls of diesel and jet fuel as a result of intentionally increasing inventory compared to the three months ended March 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

22

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

(14) Leases

Our company headquarters is located in downtown Houston, Texas.  We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10 year term expiring in 2017, includes free rent periods and escalating rent payment provisions, and requires payment of a portion of related actual operating expenses.  Rent expense is recognized on a straight-line basis.  For the three months ended March 31, 2016 and 2015, rent expense totaled $29,857 and $25,829, respectively.

(15) Income Taxes

Income Tax Benefit (Expense).  Income tax benefit (expense) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016		2015
Current:
Federal	$	-	$	(99,281	)
State		-		(82,853	)
Deferred:
Federal		1,165,901		(1,807,484	)
	$	1,165,901	$	(1,989,618	)

The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of TMT make it similar to an income tax.  Accordingly, TMT is treated as an income tax for financial reporting purposes.

Deferred Income Taxes.  Deferred income tax balances reflect the effects of temporary differences between the carrying amounts of assets and liabilities and their tax bases, as well as from NOL carryforwards.  We state those balances at the enacted tax rates we expect will be in effect when taxes are actually paid.  NOL carryforwards and deferred tax assets represent amounts available to reduce future taxable income.

NOL Carryforwards.  Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, in connection with a series of private placements, and in 2012, as a result of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income.  In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $18.8 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of $638,196 per year.  Unused portions of the annual use limitation amount may be used in subsequent years.  As a result of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused.  NOL carryforwards that were generated after the 2012 ownership change are not subject to an annual use limitation under IRC Section 382 and may be used in addition to available amounts of NOL carryforwards generated prior to the ownership change.

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23

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused as a result of the IRC Section 382 limitation):

	Net Operating Loss Carryforward
	Pre-Ownership			Post-Ownership			Total
Balance at December 31, 2014	$	10,766,912		$	12,145,789		$	22,912,701
Net operating loss carryforwards utilized		(1,152,463	)		(2,528,848	)		(3,681,311	)
								-
Balance at December 31, 2015		9,614,449			9,616,941			19,231,390
Net operating losses		-			5,871,350			5,871,350
Balance at March 31, 2016	$	9,614,449		$	15,488,291		$	25,102,740

Deferred Tax Assets and Liabilities.  At March 31, 2016 and December 31, 2015, approximately $4.8 million and $3.6 million, respectively, of net deferred tax assets remained available for future use.  Significant components of deferred tax assets and liabilities for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	10,805,253		$	8,815,794
Start-up costs (Nixon Facility)		1,476,365			1,510,699
Asset retirement obligations liability/deferred revenue		711,507			717,723
Unrealized hedges		-			62,356
AMT credit and other		219,814			302,086
Total deferred tax assets		13,212,939			11,408,658
Deferred tax liabilities:
Fair market value adjustments		(46,116	)		(46,116	)
Unrealized hedges		(404,818	)		-
Basis differences in property and equipment		(5,718,545	)		(5,484,983	)
Total deferred tax liabilities		(6,169,479	)		(5,531,099	)
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

Deferred tax assets (liabilities) on a current and noncurrent basis for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Current deferred tax assets	$	4,845,465		$	3,486,746
Noncurrent deferred tax assets, net		2,197,995			2,390,813
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

24

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Valuation Allowance. As of each reporting date, management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets.  As of March 31, 2016 and December 31, 2015, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $4.8 million and $3.6 million, respectively, were realizable, and as a result, reflected a valuation allowance accordingly.

Uncertain Tax Positions. We have adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three months ended March 31, 2016 and 2015. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2012, or after and by the state of Texas for tax years ending December 31, 2011, or after.  We believe there are no uncertain tax positions for both federal and state income taxes.

(16) Earnings Per Share

A reconciliation between basic and diluted income per share for the periods indicated was as follows:

	Three Months Ended March 31,
	2016			2015
Net income (loss)	$	(2,149,084	)	$	3,701,364
Basic and diluted income per share	$	(0.21	)	$	0.35
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,457,794			10,449,444

Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

(17) Fair Value Measurement

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

25

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Generally accepted accounting principles establish a framework for measuring the fair value.  That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2015 and 2014 due to their short-term maturities. The fair value of our long-term debt, net including the current portion at March 31, 2016 and December 31, 2015 was $34,334,877 and $34,781,186, respectively. The fair value of our debt was determined using a Level 3 hierarchy.

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 and the basis for the measurement:

			Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at March 31, 2016		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	1,190,640	$	1,190,640	$	-	$	-

				Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015			Quoted Prices in Active Markets  for Identical Assets or Liabilities (Level 1)			Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(183,400	)	$	(183,400	)	$	-	$	-

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

(18) Inventory Risk Management

Management periodically determines whether to maintain, increase, or decrease inventory levels based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows.  Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled by Genesis with cash.

26

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

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

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

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

As of March 31, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in bbls):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2016		2017		2018
Refined petroleum products and crude oil -
net short positions		460,000		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2016 and December 31, 2015:

		Fair Value
		March 31,		December 31,
Asset Derivatives	Balance Sheets Location	2016		2015
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	1,190,640	$	(183,400	)

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended March 31,
Derivatives	Statements of Operations Location	2016			2015
Commodity contracts	Cost of refined products sold	$	(492,528	)	$	927,584

(19) Commitments and Contingencies

Operating Agreement. See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to the Operating Agreement.

Genesis Agreements. We were previously subject to three agreements with Genesis and its affiliates.  Under the Construction and Funding Agreement, Milam committed funding for the Nixon Facility’s start-up refurbishment.  Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service.  As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, we now receive up to 80% of the Gross Profits as our Profit Share under the Joint Marketing Agreement, which is described below.  Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows:

27

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

Crude Supply Agreement. Under the Crude Supply Agreement, GEL is our exclusive supplier of crude oil and condensate. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to us pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described above. In addition, GEL has a first right of refusal to use three petroleum storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years expiring in August 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice; and

Joint Marketing Agreement. Under the Joint Marketing Agreement, we, together with GEL, jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. GEL is responsible for all product transportation scheduling; we are responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same.  All payments for the sale of output produced at the Nixon Facility are made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement).  As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, certain aspects related to the distribution of Gross Profits under the Joint Marketing Agreement no longer apply.  Key applicable provisions are as follows:

- We are entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees, if incurred, not to exceed $50,000 per month.  We assigned our rights to weekly payments and reimbursement of accounting fees under the Joint Marketing Agreement to LEH pursuant to the Operating Agreement. If Gross Profits are insufficient to cover Operations Payments, then GEL may: (i) reduce Operations Payments by an amount representing the difference between the Operations Payments and the Gross Profits for such monthly period, or (ii) provide the Operations Payments with such Operations Payments being considered deficit amounts owing to GEL.  If Gross Profits are negative, then we are not entitled to receive Operations Payments and GEL may recoup any losses sustained by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated; and

- GEL is entitled to receive an administrative fee in the amount of $150,000 per month relating to the performance of its obligations under the Joint Marketing Agreement (the “Performance Fee”). GEL shall be paid 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share and we shall be paid 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and us in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the our Profit Share.  The GEL Profit Share plus the Performance Fee are collectively referred to in this Quarterly Report as the Joint Marketing Agreement Profit Share (the “JMA Profit Share”).

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

Pursuant to a Letter Agreement Regarding Subordination of GEL Transaction Documents dated in June 2015, we, among other things, assigned our rights to payments under the Crude Supply Agreement and Joint Marketing Agreement as collateral in favor of Sovereign Bank, a Texas state bank (“Sovereign”), as lender and lienholder pursuant to that certain Loan and Security Agreementbetween us andSovereign dated in June 2015 in the principal amount of $25.0 million (the “Term Loan Due 2034”).  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for further discussion related to the Term Loan Due 2034.

LE has a dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement.  On May 2, 2016, GEL filed a lawsuit in Texas state court in Harris County. On May 13, 2016, LE filed a Demand for Arbitration with the American Arbitration Association to bring the dispute to resolution. We are not presently able to reasonably estimate the outcome related to the lawsuit and as such, have not recorded a liability in the consolidated balance sheets.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Notes to Consolidated Financial Statements (Continued)

FLNG Master Easement Agreement. Pursuant to a Master Easement Agreement dated in December 2013, we provide FLNG Land II, Inc., a Delaware corporation (“FLNG”) with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across certain of our property to certain property of FLNG (the “Access Easement”) and (ii) a pipeline easement and right of way across certain of our property to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”). Under the agreement, FLNG will make payments to us in the amount of $500,000 in October of each year through 2019.  Thereafter, FLNG will make payments to us in the amount of $10,000 in October of each year for so long as FLNG desires to use the Access Easement.

Supplemental Pipeline Bonds. In order to cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, the Bureau of Ocean Energy Management (the “BOEM”) generally requires that lessees and rights-of-way holders demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied, unless the BOEM exempts the lessee or rights-of-way holder from such financial assurance requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by the BOEM.

In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking outlining proposed changes to financial assurance requirements in order to modernize financial assurance and risk management and better address potential costs and liabilities of offshore energy development. Part of the Advanced Notice of Proposed Rulemaking includes the BOEM revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit based model.  Following a public comment period, the BOEM plans to publish a revised notice to lessees in 2016 that will outline new financial assurance requirements.

In August 2015, we received a letter from the BOEM requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. We are currently working with the BOEM to develop a tailored plan to address the financial assurance requirements. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. At March 31, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM.

Financing Agreements. See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to financing agreements.

Nixon Facility Expansion. We have made and continue to make capital and efficiency improvements to the Nixon Facility. As a result, we have incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and construction of additional petroleum storage tanks.

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

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

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

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

In this report, the words “Blue Dolphin,” “we,” “us” and “our” refer to Blue Dolphin Energy Company and its subsidiaries. You should read the following discussion together with the financial statements and the related notes included elsewhere in our Quarterly Report for the quarterly period ended March 31, 2016 (the “Quarterly Report”), as well as with the risk factors, financial statements, and related notes included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the “Annual Report”).  

Forward Looking Statements

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

Forward-looking statements reflect our current expectations regarding future events, results, or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized, or materially affect our financial condition, results of operations and cash flows.  Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

Risks Related to Our Business and Industry

· dangers inherent in oil and gas operations that could cause disruptions and expose us to potentially significant losses, costs or liabilities and reduce our liquidity;

· geographic concentration of our assets, which creates a significant exposure to the risks of the regional economy;

· competition from companies having greater financial and other resources;

· laws and regulations regarding personnel and process safety, as well as environmental, health, and safety, for which failure to comply may result in substantial fines, criminal sanctions, permit revocations, injunctions, facility shutdowns, and/or significant capital expenditures;

· insurance coverage that may be inadequate or expensive;

· related party transactions with LEH and its affiliates, which may cause conflicts of interest;

· capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;

· our ability to use net operating loss (“NOL”) carryforwards to offset future taxable income for U.S. federal income tax purposes, which are subject to limitation; and

· terrorist attacks, cyber-attacks, threats of war, or actual war may negatively affect our operations, financial condition, results of operations, and cash flows.

Risks Related to Our Refinery Operations Business Segment

· volatility of refining margins;

· volatility of crude oil, other feedstocks, refined petroleum products, and fuel and utility services;

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

· loss of market share by a key customer or consolidation among our customer base;

· failure to grow or maintain the market share for our refined petroleum products;

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

· our reliance on third-parties for the transportation of crude oil and condensate into and refined petroleum products out of the Nixon Facility;

· interruptions in the supply of crude oil and condensate sourced in the Eagle Ford Shale;

· changes in the supply/demand balance in the Eagle Ford Shale that could result in lower margins on refined petroleum products;

· hedging of our refined petroleum products and crude oil and condensate inventory, which may limit our gains and expose us to other risks;

· our dependence on Genesis Energy, LLC (“Genesis”) and its affiliates for crude oil and condensate sourcing, inventory risk management, hedging, and refined petroleum product marketing;

· loss of executive officers or key employees, as well as a shortage of skilled labor or disruptions in our labor force, which may make it difficult to maintain productivity;

· our dependence on Lazarus Energy Holdings, LLC (“LEH”) for financing and management of our properties;  and

· regulation of greenhouse gas emissions, which could increase our operational costs and reduce demand for our products.

Risks Related to Our Pipelines and Oil and Gas Properties

· required increases in bonds or other sureties in order to maintain compliance with regulatory requirements, which could significantly impact our liquidity and financial condition; and

· more stringent regulatory requirements related to asset retirement obligations (“AROs”), which could significantly increase our estimated future AROs.

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

Overview

Blue Dolphin (http://www.blue-dolphin-energy.com) is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refinery Operations

The Nixon Facility is situated on approximately 56 acres in Nixon, Wilson County, Texas.  The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, and related loading and unloading facilities and utilities.  At March 31, 2016, the site contained approximately 520,000 bbls of crude oil, condensate, and refined petroleum product storage capacity.  We are currently constructing an additional 578,000 bbls of petroleum storage capacity at the Nixon Facility.  When construction is complete, total crude oil, condensate, and refined petroleum product storage capacity at the Nixon Facility will exceed 1,000,000 bbls.

With a current capacity of 15,000 bpd, the Nixon Facility is considered a “topping unit” because it is primarily comprised of a crude distillation unit, the first stage of the crude oil refining process.  The Nixon Facility’s current level of complexity allows us to refine crude oil and condensate into finished and intermediate petroleum products. Our jet fuel is sold in nearby markets, and our intermediate products, including LPG, naphtha, HOBM, and AGO are sold to wholesalers and nearby refineries for further blending and processing.  The Nixon Facility uses light crude oil and condensate sourced in the Eagle Ford Shale as feedstock.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

The following diagram reflects a high level overview of the current refining process at the Nixon Facility:

Example represents a simplified plant configuration.  The specific configuration will vary based on various market and operational factors.

Pipeline Transportation

Our pipeline transportation operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines, as well as leasehold interests in oil and natural gas properties, in the Gulf of Mexico. Our pipeline transportation operations represented less than 1% of total revenue for the three months ended March 31, 2016 and 2015.

Structure and Management

We were formed as a Delaware corporation in 1986.  We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the “Operating Agreement”).  Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer and President of Blue Dolphin, as well as a majority owner of LEH.   See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Accounts Payable, Related Party,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” of this Quarterly Report for additional disclosures related to the Operating Agreement, Jonathan Carroll, and LEH.

Our operations are conducted through the following operating subsidiaries:

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

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

· Blue Dolphin Pipe Line Company, a Delaware corporation;

· Blue Dolphin Petroleum Company, a Delaware corporation; and

· Blue Dolphin Services Co., a Texas corporation.

See "Part I, Item 2. Properties” of the Annual Report for additional information regarding our operating subsidiaries.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Major Influences on Results of Operations

Our earnings and cash flows from our refinery operations business segment are primarily affected by the relationship between refined petroleum product prices and the prices for crude oil and other feedstocks. Crude oil refining is primarily a margin-based business, and in order to increase profitability, it is important for a refinery to maximize the yields of higher value finished and intermediate products and to minimize the costs of feedstock and operating expenses.  Our cost to acquire crude oil and condensate and the price for which our refined petroleum products are ultimately sold depend on several factors, many of which are beyond our control, including the supply of, and demand for, crude oil and refined petroleum products, which depend on changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of and access to transportation infrastructure, the availability of imports, the marketing of competitive fuel, and governmental regulations, among other factors.

Crude oil and refined petroleum product prices are also affected by other factors, such as local and general market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined petroleum products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments, and other factors beyond our control are likely to continue to play an important role in crude oil refining industry economics.  Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined petroleum products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a negative impact on product margins. In addition to current market conditions, there are long-term factors that may impact the demand for refined petroleum products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

Key Relationships

Relationship with LEH

We rely on cash from operations to fund our working capital requirements. LEH manages and operates all of our properties pursuant to the Operating Agreement.  For services rendered, LEH receives reimbursements and fees.

See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Accounts Payable, Related Party” for additional disclosures related to LEH and the Operating Agreement.

Relationship with Genesis

We were previously subject to three agreements with Genesis and its affiliates.  Under the Construction and Funding Agreement, Milam Services, Inc. (“Milam”) committed funding for the Nixon Facility’s initial start-up refurbishment.  Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service.  As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, we now receive up to 80% of the Gross Profits as our Profit Share under the Joint Marketing Agreement. Our relationship with Genesis and its affiliates is currently governed by two agreements – the Crude Supply Agreement and the Joint Marketing Agreement.

LE has a dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement.  On May 2, 2016, GEL filed a lawsuit in Texas state court in Harris County. On May 13, 2016, LE filed a Demand for Arbitration with the American Arbitration Association to bring the dispute to resolution. We are not presently able to reasonably estimate the outcome related to the lawsuit and as such, have not recorded a liability in the consolidated balance sheets.

See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for additional disclosures related to the Crude Supply Agreement, Joint Marketing Agreement, and our relationship with Genesis.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Results of Operations

We have two reportable business segments: (i) Refinery Operations and (ii) Pipeline Transportation.  Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility and represent approximately 99% of our operations. Business activities related to our Pipeline Transportation business segment are primarily conducted in the Gulf of Mexico through our pipeline assets and leasehold interests in oil and gas properties and represent less than 1% of our operations.

In this Results of Operations section, we review:

· definitions of key financial performance measures used by management;

· consolidated results, which include our Pipeline Transportation business segment;

· non-GAAP financial results; and

· Refinery Operations business segment results.

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

GLOSSARY OF SELECTED PERFORMANCE MEASURES

Management uses generally accepted accounting principles (“GAAP”) and certain non-GAAP performance measures to assess our results of operations. Certain performance measures used by management to assess our operating results and the effectiveness of our business segments are considered non-GAAP performance measures. These performance measures may differ from similar calculations used by other companies within the petroleum industry, thereby limiting their usefulness as a comparative measure.

For our refinery operations business segment, we refer to certain refinery throughput and production data in the explanation of our period over period changes in results of operations.  For our consolidated results, we refer to our consolidated statements of operations in the explanation of our period over period changes in results of operations.

Below are definitions of key financial performance measures used by management:

Adjusted Earnings Before Interest, Income Taxes and Depreciation (“EBITDA”). Reflects EBITDA excluding the JMA Profit Share. -  Refinery Operations Adjusted EBITDA. Reflects adjusted EBITDA for our refinery operations business segment. -  Total Adjusted EBITDA. Reflects adjusted EBITDA for our refinery operations and pipeline transportation business segments, as well as corporate and other. Capacity Utilization Rate. A percentage measure that indicates the amount of available capacity being used at the Nixon Facility. The rate is calculated by dividing total refinery throughput on a bpd basis or total refinery production on a bpd basis by the total capacity of the Nixon Facility, which is currently 15,000 bpd. Cost of Refined Products Sold. Primarily includes purchased crude oil and condensate costs, as well as transportation, freight and storage costs. Depletion, Depreciation and Amortization. Represents property and equipment, as well as intangible assets that are depreciated or amortized based on the straight-line method over the estimated useful life of the related asset. Downtime. Scheduled or unscheduled periods in which the Nixon Facility is not operable. Downtime may be required for a variety of reasons, including maintenance, inspection and equipment repair, voluntary regulatory compliance measures, and cessation or suspension by regulatory authorities. Easement, Interest and Other Income. Reflects income related to: FLNG Master Easement Agreement. An easement agreement with FLNG Land II, Inc., a Delaware corporation (“FLNG”), which is recorded as land easement revenue and recognized monthly as earned. EBITDA. Reflects earnings before: (i) interest income (expense), (ii) income taxes, and (iii) depreciation and amortization. -  Refinery Operations EBITDA. Reflects EBITDA for our refinery operations business segment. -  Total EBITDA. Reflects EBITDA for our refinery operations and pipeline transportation business segments, as well as corporate and other. General and Administrative Expenses. Primarily include corporate costs, such as accounting and legal fees, office lease expenses, and administrative expenses. Income Tax Expense. Includes federal and state taxes, as well as deferred taxes, arising from temporary differences between income for financial reporting and income tax purposes. JMA Profit Share. Represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement; is an indirect operating expense. Net Income. Represents total revenue from operations less total cost of operations, total other expense, and income tax expense. Operating Days. The number of days in a period in which the Nixon Facility operated. Downtime is excluded from operating days. Refinery Operating Expenses. Reflect the direct operating expenses of the Nixon Facility, including direct costs of labor, maintenance materials and services, chemicals and catalysts and utilities. Includes fees paid to LEH to manage and operate the Nixon Facility pursuant to the Operating Agreement. Refinery Operating Income. Reflects refined petroleum product sales less direct operating costs (including cost of refined products sold and refinery operating expenses) and the JMA profit share. Revenue from Operations. Primarily consists of refined petroleum product sales, but also includes tank rental and pipeline transportation revenue. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. Total Refinery Production. Refers to the volume processed as output through the Nixon Facility. Refinery production includes finished petroleum products, such as jet fuel, and intermediate petroleum products, such as LPG, naphtha, HOBM and AGO. Total Refinery Throughput. Refers to the volume processed as input through the Nixon Facility. Refinery throughput includes crude oil and condensate and other feedstocks.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Consolidated Results

March 31, 2016 (the “Current Period”) Compared to March 31, 2015 (the “Prior Period”).

Total Revenue from Operations. For the Current Period we had total revenue from operations of $31,512,276 compared to total revenue from operations of $61,392,349 for the Prior Period.  The approximate 49% decrease in total revenue from operations was primarily the result of a significant decrease in commodity prices in the Current Period compared to the Prior Period. Additionally, we sold less bbls of refined petroleum products in the Current Period to intentionally build inventory to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies. The majority of our revenue in the Current Period came from refined petroleum product sales, which generated revenue of $31,193,137, or approximately 99% of total revenue from operations, compared to $61,067,062, or more than 99% of total revenue from operations, in the Prior Period. We recognized $291,487 in tank rental revenue in the Current Period compared to $286,892 in the Prior Period.  Tank rental revenue was relatively flat between the Current Period and Prior Period.

Cost of Refined Products Sold. Cost of refined products sold was $30,993,477 for the Current Period compared to $49,387,449 for the Prior Period.  The approximate 37% decrease in cost of refined products sold was the result of a significant decrease in commodity prices and an intentional increase in refined petroleum product inventory levels in the Current Period compared to the Prior Period.

Refinery Operating Expenses.  We recorded refinery operating expenses of $3,437,015 in the Current Period compared to $2,880,971 in the Prior Period, an increase of approximately 19%.  Refinery operating expenses per bbl of throughput were $2.90 in the Current Period compared to $2.71 in the Prior Period.  The increase in refinery operating expenses per bbl of throughput between the periods was a result of off-site tank leasing expense, as well as an increase in total refinery throughput. We utilize a short-term tank lease agreement with Ingleside Crude, LLC (“Ingleside”) to meet periodic additional storage needs, such as during the Current Period associated with increased inventory. See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to the Operating Agreement.

JMA Profit Share.  During the Current Period we experienced a benefit of $671,092 relative to the JMA Profit Share compared to an expense of $2,438,637 for the Prior Period.  Under the Joint Marketing Agreement, Gross Profits are shared between us and GEL.  If Gross Profits are negative, then the JMA Profit Share will reflect a benefit to us until such losses are covered.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

General and Administrative Expenses. We incurred general and administrative expenses of $357,004 in the Current Period compared to $345,884 in the Prior Period.  The slight increase in general and administrative expenses in the Current Period compared to the Prior Period primarily related to personnel related costs.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $440,453 in the Current Period compared to $399,231 in the Prior Period.  The approximate 10% increase in depletion, depreciation and amortization expenses for the Current Period compared to the Prior Period primarily related to additional depreciable refinery assets that were placed in service.

Easement, Interest and Other Income.  We recorded $131,763 in easement, interest and other income for the Current Period compared to $66,007 in the Prior Period.  The significant increase primarily related to easement income from FLNG.

Income Tax Benefit (Expense).  We recognized an income tax benefit of $1,165,901 in the Current Period compared to an income tax expense of $1,989,618 in the Prior Period, which primarily related to deferred federal income taxes.  See “Part I, Financial Information, Item 1. Financial Statements – Note (15) Income Taxes” of this Quarterly Report for additional disclosures related to income taxes.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Net Income (Loss).  For the Current Period, we reported a net loss of $2,149,084, or a loss of $0.21 per share, compared to net income of $3,701,364, or income of $0.35 per share, for the Prior Period.  The $0.56 per share decrease in net income between the periods was the result of lower margins on refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses, which were partially offset by an income tax benefit during the Current Period.

Non-GAAP Financial Measures

To supplement our consolidated results, management uses certain non-GAAP financial measures. These non-GAAP financial measures are reconciled to GAAP-based results below. These non-GAAP financial measures should not be considered an alternative for GAAP results. The adjustments are provided to enhance an overall understanding of our financial performance for the applicable periods and are indicators management believes are relevant and useful. These performance measures may differ from similar calculations used by other companies within the petroleum industry, thereby limiting their usefulness as a comparative measure. For comparative GAAP results, see “Part I, Financial Information, Item 1. Financial Statements” of this Quarterly Report.

Adjusted EBITDA and EBITDA, Reconciliation to GAAP.

	Three Months Ended March 31, 2016												Three Months Ended March 31, 2015
	Segment												Segment
	Refinery			Pipeline			Corporate &						Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total			Operations			Transportation			Other			Total
Revenue from operations	$	31,484,624		$	27,652		$	-		$	31,512,276		$	61,353,954		$	38,395		$	-		$	61,392,349
Less: cost of operations(1)		(34,422,853	)		(122,128	)		(224,775	)		(34,769,756	)		(52,259,470	)		(53,912	)		(408,048	)		(52,721,430	)
Other non-interest income(2)		-			130,665			-			130,665			-			62,500			-			62,500
Adjusted EBITDA		(2,938,229	)		36,189			(224,775	)		(3,126,815	)		9,094,484			46,983			(408,048	)		8,733,419
Less:  JMA Profit Share(3)		671,092			-			-			671,092			(2,438,637	)		-			-			(2,438,637	)
EBITDA	$	(2,267,137	)	$	36,189		$	(224,775	)	$	(2,455,723	)	$	6,655,847		$	46,983		$	(408,048	)	$	6,294,782
Depletion, depreciation and amortization											(440,453	)											(399,231	)
Interest expense, net											(418,809	)											(204,569	)
Income before income taxes											(3,314,985	)											5,690,982
Income tax benefit (expense)											1,165,901												(1,989,618	)
Net income										$	(2,149,084	)										$	3,701,364

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue.  See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” of this Quarterly Report for further discussion related to FLNG.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement.  See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion of the Joint Marketing Agreement.

Adjusted EBITDA and EBITDA, Current Period Compared to Prior Period.

Refinery Operations Adjusted EBITDA.  Refinery operations adjusted EBITDA for the Current Period was a loss of $2,938,229 compared to income of $9,094,484 for the Prior Period.  This represented a decrease in refinery operations adjusted EBITDA of $12,032,713 for the Current Period compared to the Prior Period. The decrease in refinery operations adjusted EBITDA between the periods was primarily the result of lower margins on refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses.

Total Adjusted EBITDA.  Total adjusted EBITDA for the Current Period was a loss of $3,126,815 compared to income of $8,733,419 for the Prior Period.  This represented a decrease in total adjusted EBITDA of $11,860,234 for the Current Period compared to the Prior Period.  The decrease in total adjusted EBITDA between the periods was primarily the result of lower margins on refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refinery Operations EBITDA.  Refinery operations EBITDA for the Current Period was a loss of $2,267,137 compared to income of $6,655,847 for the Prior Period.  This represented a decrease in refinery operations EBITDA of $8,922,984 for the Current Period compared to the Prior Period.  The decrease in refinery operations EBITDA between the periods was the result of lower margins on refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses.

Total EBITDA.  Total EBITDA for the Current Period was a loss of $2,455,723 compared to an income of $6,294,782 for the Prior Period.  This represented a decrease in total EBITDA of $8,750,505 for the Current Period compared to the Prior Period. The decrease in total EBITDA between the periods was primarily the result of lower margins from refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses.

Refinery Operating Income (Loss), Reconciliation to GAAP.

	Three Months Ended March 31,
	2016			2015
Total refined petroleum product sales	$	31,193,137		$	61,067,062
Less:  Cost of refined petroleum products sold		(30,993,477	)		(49,387,449	)
Less:  Refinery operating expenses		(3,437,015	)		(2,880,971	)
Refinery operating income before JMA Profit Share		(3,237,355	)		8,798,642
Less:  JMA Profit Share		671,092			(2,438,637	)
Refinery operating income (loss)	$	(2,566,263	)	$	6,360,005
Total refined petroleum product sales (bbls)		939,453			1,026,884

Refinery Operating Income (Loss), Current Period Compared to Prior Period.

Refinery Operating Income (Loss).  Refinery operating loss totaled $2,566,263 for the Current Period compared to refinery operating income of $6,360,005 for the Prior Period, representing a decrease of $8,926,268. The decrease in refinery operating income (loss) between the periods was primarily the result of lower margins from refined petroleum products, lower refined petroleum product sales associated with increased inventory, and higher refinery operating expenses.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refinery Operations Business Segment Results

Refinery Throughput and Production Data.

Following are refinery operational metrics for the Nixon Facility:

	Three Months Ended March 31,
	2016			2015
Operating Days		91			90
Downtime		-			-
Total refinery throughput
bbls		1,183,806			1,062,388
bpd		13,009			11,804
Total refinery production
bbls		1,154,307			1,044,210
bpd		12,685			11,602
Capacity utilization rate
refinery throughput		86.7	%		78.7	%
refinery production		84.6	%		77.3	%

Note:  The difference between total refinery throughput (volume processed as input) and total refinery production (volume processed as output) represents refinery fuel and energy use.

Current Period Compared to Prior Period.

Operating Days.  The Nixon Facility operated for a total of 91 days in the Current Period compared to operating for a total of 90 days in the Prior Period.

Downtime. The Nixon Facility experienced no downtime in the Current Period or Prior Period.

Total Refinery Throughput.  For the Current Period, the Nixon Facility processed 1,183,809 bbls, or 13,009 bpd, of crude oil and condensate compared to 1,062,388 bbls, or 11,804 bpd, of crude oil and condensate for the Prior Period.  Total refinery throughput increased 121,418 bbls, or approximately 11%, for the Current Period compared to the Prior Period, which represented an increase of 1,205 bpd.  Total refinery throughput increased as a result of efficiencies derived from debottlenecking efforts and optimization of the naphtha stabilizer and depropanizer units.

Total Refinery Production.  For the Current Period, the Nixon Facility produced 1,154,307 bbls, or 12,685 bpd, of refined petroleum products compared to 1,044,210 bbls, or 11,602 bpd, of refined petroleum products for the Prior Period.  Total refinery production increased 110,097 bbls, or approximately 11%, for the Current Period compared to the Prior Period, which represented an increase of 1,082 bpd.  Total refinery production increased as a result of efficiencies derived from debottlenecking efforts and optimization of the naphtha stabilizer and depropanizer units.

Capacity Utilization Rate.  The capacity utilization rate for refinery throughput for the Current Period was 86.7% compared to 78.7% for the Prior Period, reflecting an approximate 8% increase.  The capacity utilization rate for refinery production for the Current Period was 84.6% compared to 77.3% for the Prior Period, reflecting an approximate 7% increase.  Capacity utilization rates increased as a result of efficiencies derived from debottlenecking efforts and optimization of the naphtha stabilizer and depropanizer units.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Refined Petroleum Product Sales Summary.

See “Part I, Financial Information, Item 1. Financial Statements - Note (13) Concentration of Risk” of this Quarterly Report for a discussion of refined petroleum product sales.

Refined Petroleum Product Economic Hedges.

The effect of economic hedges on our refined petroleum product inventories are contained within cost of operations within our refinery operations business segment.  For the Current Period, our refinery operations business segment recognized a loss of $881,512 on settled transactions and a gain of $1,374,040 on the change in value of open contracts from December 31, 2015 to March 31, 2016.  For the Prior Period, our refinery operations business segment recognized a gain of $1,475,774 on settled transactions and a loss of $548,190 on the change in value of open contracts from December 31, 2014 to March 31, 2015.

Liquidity and Capital Resources

At March 31, 2016 and December 31, 2015, we had cash and cash equivalents of $560,273 and $1,853,875, respectively. Restricted cash, current totaled $3,013,035 and $3,175,299 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, noncurrent totaled $12,551,748 and $15,616,478 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, current primarily represents: (i) a construction contingency account under which Sovereign Bank, a Texas state bank (“Sovereign”) will fund contingencies and (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement.  Restricted cash, noncurrent represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks.  

We currently rely on our profit share under the Joint Marketing Agreement and LEH to fund our working capital requirements.  During months in which we receive no profit share under the Joint Marketing Agreement, LEH may, but is not required to, fund our working capital requirements.  There can be no assurances that LEH will continue to fund our working capital requirements.

As of March 31, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign. We are currently making our scheduled monthly payments in accordance with the terms and conditions of the loan agreements.  See “Part I, Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to Sovereign, our long-term debt, and financial covenant violations.

We believe that our cash flows from operations, existing cash and cash equivalents, and proceeds from credit facilities will be sufficient to support our operations and capital expenditures for the next 12 to 18 months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and the financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

Cash Flow

Our cash flow from operations for the periods indicated was as follows:

	Three Months Ended March 31,
	2016			2015
Cash flow from operations
Adjusted income (loss) from operations	$	(4,308,132	)	$	6,517,934
Change in assets and current liabilities		3,905,612			(3,937,342	)
Total cash flow from operations		(402,520	)		2,580,592
Cash inflows (outflows)
Payments on long term debt		(478,431	)		(300,106	)
Change in restricted cash for investing activities		3,064,730			-
Capital expenditures		(3,639,645	)		(1,291,915	)
Change in restricted cash for financing activities		162,264			(2,598	)
Total cash outflows		(891,082	)		(1,594,619	)
Total change in cash flows	$	(1,293,602	)	$	985,973

For the Current Period, we experienced negative cash flow from operations of $402,520 compared to positive cash flow from operations of $2,580,592 for the Prior Period. The $2,983,112 decrease in cash flow from operations period over period was primarily the result of the decrease in net income.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Underlying factors in our cash flow reduction included lower refining margins, lower sales volume due to an intentional build in inventory, and an increase in accounts payable. Typical construction supply chain issues related to expansion of the Nixon Facility led to the increase in accounts payable.  Inventory was intentionally increased to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

At March 31, 2016, the intentional inventory buildup represented approximately 204,000 bbls. Management periodically determines whether to change product mix, as well as maintain, increase, or decrease inventory levels based on various factors, including the crude oil pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows.

Capital Spending

We are currently expanding the Nixon Facility and believe that capital and efficiency improvements will enable us to remain competitive by: (i) generating additional revenue from leasing product and crude storage to third parties; (ii) having crude and product storage to support refinery throughput and future expansion of up to 30,000 bbls per day; and (iii) increasing the processing capacity and complexity of the Nixon Facility.

Capital expenditures in the Current Period totaled $3,639,645 compared to $1,291,915 in the Prior Period, primarily reflecting the completed construction of 122,000 bbls of petroleum storage capacity at the Nixon Facility. We are constructing an additional 578,000 bbls of petroleum storage.  When expansion of the Nixon Facility is complete, total crude oil, condensate, and refined petroleum product storage capacity at the Nixon Facility will exceed 1,000,000 bbls.  We are funding capital expenditures at the Nixon Facility primarily through borrowings.  See “Part I, Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to borrowings for capital spending.

Execution of our business strategy depends on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and the financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive, and other factors beyond our control.  There can be no assurance that our business strategy will achieve the anticipated outcomes.  In the event our business strategy is unsuccessful, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.  See “Part I, Item 1A. Risk Factors” of our Annual Report for risk factors related to working capital, liquidity and Nixon Facility downtime.

Contractual Obligations

Related Party.

Ingleside. At March 31, 2016 and December 31, 2015, accounts payable, related party to Ingleside for off-site storage tank fees totaled $172,389 and $300,000, respectively.

LEH.  At March 31, 2016 and December 31, 2015, accounts payable, related party to LEH under the Operating Agreement totaled $77,836 and $0, respectively.  At December 31, 2015, we were in a prepaid position with respect to LEH under the Operating Agreement.  Prepaid related party operating expenses to LEH totaled $0 and $624,570 at March 31, 2016 and December 31, 2015, respectively.

For the three months ended March 31, 2016 and 2015, refinery operating expenses to Ingleside and LEH totaled $3,437,015 (approximately $2.90 per bbl of throughput) and $2,880,971 (approximately $2.71 per bbl of throughput), respectively, and were reflected as refinery operating expenses in our consolidated statements of operations.

Jonathan Carroll.  At March 31, 2016 and December 31, 2015, accounts payable, related party to Jonathan Carroll pursuant to Guaranty Fee Agreements totaled $158,331 and $0, respectively.

See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to Ingleside, LEH, and Jonathan Carroll.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Genesis

We are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice.  These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain these relationships or our relationships are not on good terms, it could have a material adverse effect on our operations, liquidity and financial condition. See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to Genesis, the Joint Marketing Agreement, and the Crude Supply Agreement.

Indebtedness

The principal balances outstanding on our long-term debt, net for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
First Term Loan Due 2034	$	22,862,799		$	23,019,271
Second Term Loan Due 2034		9,169,132			9,232,328
Capital Leases		262,972			304,618
Notre Dame Debt		1,300,000			1,300,000
Term Loan Due 2017		739,974			924,969
		34,334,877			34,781,186
Less: Long-term debt less amortized debt issue costs, current portion		(32,942,090	)		(1,934,932	)
	$	1,392,787		$	32,846,254

As of March 31, 2016, LE and LRM were in violation of the debt service coverage ratio and the current ratio financial covenants under the First Term Loan Due 2034 and Second Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 and Second Term Loan Due 2034 have been classified within the current portion of long-term debt on our consolidated balance sheets.  See “Part I, Financial Information, Item 1. Financial Statements – Note (1) Organization – Operating Risks and Note (9) Long-Term Debt, Net" of this Quarterly Report for additional disclosures related to Sovereign, the First Term Loan Due 2034, and the Second Term Loan Due 2034.

Critical Accounting Policies

Long-Lived Assets

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are included as operating expenses under the Operating Agreement and covered by LEH. Management expects to continue making improvements to the Nixon Facility based on technological advances.

We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets for the three months ended March 31, 2016 and 2015.

Pipelines and Facilities Assets. We record pipelines and facilities at cost less any adjustments for depreciation or impairment.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.

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

Revenue Recognition

We sell jet fuel in nearby markets, and our intermediate products, including LPG, naphtha, HOBM, and AGO, to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

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

Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.   Land easement revenue is recognized monthly as earned and included in other income.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

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

Asset Retirement Obligations

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

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

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

Income Taxes

We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the Current Period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any NOL carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.

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

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

See “Part I, Financial Information, Item 1. Financial Statements - Note (15) Income Taxes” of this Quarterly Report for further information related to income taxes.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

Management’s Discussion and Analysis of Financial Condition and Results of Operations (Continued)

Recently Adopted AccountingGuidance

Effective January 1, 2016, we adopted the accounting and reporting requirements included in the Financial Accounting Standards Boards’ ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. We have applied these requirements retrospectively.  Accordingly, our consolidated balance sheets at March 31, 2016 and December 31, 2015 as reflected within this Quarterly Report have been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Under the supervision of, and with the participation of our management, including our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report. Based on our evaluation, our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

During 2015, we took a number of steps to fully remediate previously identified material weakness related to a lack of formally documented accounting policies and procedures.  As a result, management concluded that our internal control over financial reporting was effective as of December 31, 2015. There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2016  that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.  See “Part II, Changes In and Disagreements with Accountants on Accounting and Financial Disclosure” of our Annual Report for a discussion related to controls and procedures.

PART II OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

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

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this Quarterly Report for the quarterly period ended March 31, 2016 (the “Quarterly Report”), careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our Annual Report for the fiscal year ended December 31, 2015 (the “Annual Report”).  These risks and uncertainties could materially and adversely affect our business, financial condition and results of operations.  Our operations could also be affected by additional factors that are not presently known to us or by factors that we currently consider immaterial to our business.  With the exception of the below risk factor, there have been no material changes in our assessment of our risk factors from those set forth in our Annual Report.

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

We currently rely on our profit share under the Joint Marketing Agreement and LEH to fund our capital requirements.  During months in which we receive no profit share under the Joint Marketing Agreement, LEH may, but is not required to, fund our capital requirements.  There can be no assurances that LEH will continue to fund our capital requirements. In the event our capital requirements are not funded by our profit share or LEH, we may experience a significant and material adverse effect on our operations.

We believe that our cash flows from operations, existing cash and cash equivalents, and proceeds from credit facilities will be sufficient to support our operations and capital expenditures for the next 12 to 18 months.  If we are unable to generate sufficient cash flows from operations or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity.  Our short-term capital needs are primarily related to repayment of certain loan agreements with Sovereign Bank, a Texas state bank (“Sovereign”). (See“Part I, Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net” of this Quarterly Report for further discussion related to loan agreements with Sovereign.)  Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades at the Nixon Facility.  In addition, from time to time, we expect to utilize significant capital to upgrade equipment, improve facilities and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.

As of March 31, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign. Our failure to comply with certain financial covenants in loan agreements could materially and adversely affect our operating results and our financial condition.

There can be no assurance that our assets or cash flow would be sufficient to fully repay borrowings under our outstanding notes payable, either upon maturity or if accelerated, or that we would be able to refinance or restructure the payments on the notes payable. If we fail to comply with financial covenants associated with certain of our long-term debt and such failure is not cured or waived, then the lender may exercise any rights and remedies available under the loan agreement(s) and applicable law including, without limitation, foreclosing on our assets. Any such action by our lender would have a material adverse effect on our financial condition and ability to continue as a going concern.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

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

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

See “Part I, Financial Information, Item. 1. Financial Statements – Note (9) Long-Term Debt, Net” of this report for disclosures related to potential defaults on debt.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

Exhibits and Financial Statement Schedules

Following is a list of documents filed as part of this Quarterly Report:

· consolidated balance sheets, consolidated statements of operations, and consolidated statements of cash flows, which appear in “Part I, Financial Information, Item 1. Financial Statements” of this Quarterly Report; and

· exhibits as listed in the exhibit index of this Quarterly Report, which is incorporated herein by reference.

Exhibits Index

No.	Description
10.1	Third Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of October 1, 2015.
10.2	Fourth Amendment to Promissory Note by and between Lazarus Energy, LLC and John H. Kissick effective as of April 1, 2016.
31.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Jonathan P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Tommy L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.LAB	XBRL Label Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

46

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 3/31/16

SIGNATURES 

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

	BLUE DOLPHIN ENERGY COMPANY (Registrant)
Date: May 16, 2016	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer)

Date:  May 16, 2016	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

47

EX-10.1

Exhibit 10.1

THIRD AMENDMENT TO PROMISSORY NOTE

This THIRD AMENDMENT TO PROMISSORY NOTE (the "Amendment") by and between Lazarus Energy, LLC, a Delaware limited liability company ("Maker")and. John H. Kissick ("Payee") is made effective as of October 1, 2015 (the "Effective Date") The Maker and the Payee shall be referenced individually as a "Party" and collectively and "Parties".

WHEREAS, the Maker and the Payee are Parties to that certain Promissory Note dated June 1, 2006, (as amended, restated, supplemented or otherwise modified from time to time in accordance with its provisions, the "Note") to which reference is hereby made for all purposes; and

WHEREAS, the Parties hereto desire to amend the Note on the terms and subject to the conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1. Definitions. Capitalized terms used and not defined in this Amendment shall have the respective meanings given them in the Note.

2. Amendments to the Note. The Note is hereby amended as follows:

(a)  Interest Rate. The annual Interest Rate on Unpaid Balance shall be sixteen per cent (16.00%).

(b)  Final Maturity. The Final Maturity shall be January 2, 2017.

3. Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Note and the Deed of Trust are and shall remain in full force and effect and are hereby ratified and confirmed by the Maker. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of Note or Deed of Trust or for any purpose except as expressly set forth herein or a consent to any further or future action on the part of the Maker that would require the waiver or consent of the Payee.

4. Successors and Assigns. This Amendment shall inure to the benefit of and be binding upon the Payee and Maker and each of their respective successors and assigns.

5. Counterparts. This Amendment may be executed in any number of counterparts, all of which shall constitute one and the same agreement, and any Party hereto may execute this Amendment by signing and delivering one or more counterparts. Delivery of an executed counterpart of this Amendment electronically or by facsimile shall he effective as delivery of an original executed counterpart of this Amendment

[Remainder of page intentionally left blank; signature page to follow]

1

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment as of the Effective Date.

Lazarus Energy LLC, as Maker
By:	/s/ JONATHAN P. CARROLL
	Jonathan P. Carroll
	President

John H. Kissick, as Payee
By:	/s/ JOHN H. KISSICK
	John H. Kissick

2

EX-10.2

Exhibit 10.2

FOURTH AMENDMENT TO PROMISSORY NOTE

This FOURTH AMENDMENT TO PROMISSORY NOTE (the "Amendment") by and between Lazarus Energy, LLC, a Delaware limited liability company ("Maker") and John H. Kissick ("Payee") is made effective as of April 1, 2016 (the "Effective Date"). The Maker and the Payee shall be referenced individually as a "Party" and collectively and "Parties".

WHEREAS, the Maker and the Payee are Parties to that certain Promissory Note dated June 1, 2006, (as amended, restated, supplemented or otherwise modified from time to time in accordance with its provisions, the "Note") to which reference is hereby made for all purposes; and

WHEREAS, the Parties hereto desire to amend the Note on the terms and subject to the conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and Ten and No/100 Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

1. Definitions.  Capitalized terms used and not defined in this Amendment shall have the respective meanings given them in the Note.

2. Amendments to the Note.  The Note is hereby amended as follows:

(a)  Interest Rate -- The annual Interest Rate on Unpaid Balance shall be sixteen percent (16.00%); and

(b)  Final Maturity -- The Final Maturity shall be January 2, 2018.

3. Limited Effect.  Except as expressly provided hereby, all of the terms and provisions of the Note and the Deed of Trust are and shall remain in full force and effect and are hereby ratified and confirmed by the Maker. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of the Note or Deed of Trust or for any purpose except as expressly set forth herein or a consent to any further or future action on the part of the Maker that would require the waiver or consent of the Payee.

4. Successors and Assigns.  This Amendment shall inure to the benefit of and be binding upon the Payee and Maker and each of their respective successors and assigns.

5. Counterparts.  This Amendment may be executed in any number of counterparts, all of which shall constitute one and the same agreement, and any Party hereto may execute this Amendment by signing and delivering one or more counterparts.  Delivery of an executed counterpart of this Amendment electronically or by facsimile shall he effective as delivery of an original executed counterpart of this Amendment.

[Remainder of page intentionally left blank; signature page to follow]

1

IN WITNESS WHEREOF, theParties hereto have executed this Amendment as of the Effective Date.

Lazarus Energy LLC, as Maker
By:	/s/ JONATHAN P. CARROLL
	Jonathan P. Carroll
	President

John H. Kissick, as Payee
By:	/s/ JOHN H. KISSICK
	John H. Kissick

2

EX-31.1

EXHIBIT 31.1

I, Jonathan P. Carroll, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  May 16, 2016	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

I, Tommy L. Byrd, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:  May 16, 2016	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary (Principal Executive Officer) of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

Date:  May 16, 2016	By:	/s/ JONATHAN P. CARROLL
		Jonathan P. Carroll
		Chairman of the Board, Chief Executive Officer, President, Assistant Treasurer and Secretary
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report of Blue Dolphin Energy Company (the “Company”) on Form 10-Q for the period ended March 31, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Tommy L. Byrd, Chief Financial Officer, Treasurer and Assistant Secretary (Principal 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.

Date:  May 16, 2016	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 16, 2016
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	0000793306
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		10,458,400
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2016

XML

Consolidated Balance Sheets (Unaudited) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 560,273	$ 1,853,875
Restricted cash	3,013,035	3,175,299
Accounts receivable, net	3,326,561	5,457,245
Prepaid expenses and other current assets	1,357,672	939,690
Deposits	229,933	395,414
Inventory	14,850,967	7,808,318
Deferred tax assets, current portion, net	4,845,465	3,486,746
Total current assets	28,183,906	23,116,587
Total property and equipment, net	53,147,209	48,841,812
Restricted cash, noncurrent	12,551,748	15,616,478
Surety bonds	1,022,000	1,022,000
Trade name	$ 303,346	303,346
Deferred tax assets, net		120,491
Total long-term assets	$ 67,024,303	65,904,127
TOTAL ASSETS	95,208,209	89,020,714
CURRENT LIABILITIES
Accounts payable	24,696,745	14,882,714
Accounts payable, related party	408,556	300,000
Asset retirement obligations, current portion	38,644	38,644
Accrued expenses and other current liabilities	1,719,195	2,990,891
Interest payable, current portion	87,558	81,467
Long-term debt less unamortized debt issue costs, current portion	32,942,090	1,934,932
Total current liabilities	59,892,788	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,939,363	1,947,220
Deferred revenues and expenses	114,661	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,392,787	32,846,254
Long-term interest payable, net of current portion	1,534,661	$ 1,482,801
Deferred tax liabilities, net	72,327
Total long-term liabilities	5,053,799	$ 36,401,360
TOTAL LIABILITIES	$ 64,946,587	$ 56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,608,400 and 10,603,802 shares issued at March 31, 2016 and December 31, 2015, respectively)	$ 106,084	$ 106,038
Additional paid-in capital	36,758,691	36,738,737
Accumulated deficit	(5,803,153)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	30,261,622	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 95,208,209	$ 89,020,714

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,608,400	10,603,802
Common stock, shares outstanding	10,608,400	10,603,802
Treasury stock, shares	150,000	150,000

XML

Consolidated Statements of Operations (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 31,193,137	$ 61,067,062
Tank rental revenue	291,487	286,892
Pipeline operations	27,652	38,395
Total revenue from operations	31,512,276	61,392,349
COST OF OPERATIONS
Cost of refined products sold	30,993,477	49,387,449
Refinery operating expenses	3,437,015	2,880,971
Joint Marketing Agreement profit share	(671,092)	2,438,637
Pipeline operating expenses	79,290	46,596
Lease operating expenses	14,652	7,316
General and administrative expenses	357,004	345,884
Depletion, depreciation and amortization	440,453	$ 399,231
Recovery of bad debt	(139,868)
Accretion expense	28,186	$ 53,215
Total cost of operations	34,539,117	55,559,299
Income (loss) from operations	(3,026,841)	5,833,050
OTHER INCOME (EXPENSE)
Easement, interest and other income	131,763	66,007
Interest and other expense	(419,907)	(208,075)
Total other expense	(288,144)	(142,068)
Income (loss) before income taxes	(3,314,985)	5,690,982
Income tax benefit (expense)	1,165,901	(1,989,618)
Net income (loss)	$ (2,149,084)	$ 3,701,364
Income (loss) per common share:
Basic	$ (0.21)	$ 0.35
Diluted	$ (0.21)	$ 0.35
Weighted average number of common shares outstanding:
Basic	10,457,794	10,449,444
Diluted	10,457,794	10,449,444

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING ACTIVITIES
Net income (loss)	$ (2,149,084)	$ 3,701,364
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	440,453	399,231
Unrealized loss (gain) on derivatives	(1,374,040)	548,190
Deferred tax expense (benefit)	(1,165,901)	1,807,484
Amortization of debt issue costs	32,122	8,450
Accretion expense	28,186	$ 53,215
Common stock issued for services	20,000
Recovery of bad debt	(139,868)
Changes in operating assets and liabilities
Accounts receivable	2,270,552	$ (1,536,092)
Prepaid expenses and other current assets	772,658	650,694
Deposits and other assets	165,481	(80,513)
Inventory	(7,042,649)	129,941
Accounts payable, accrued expenses and other liabilities	7,631,014	(2,046,849)
Accounts payable, related party	108,556	(1,054,523)
Net cash provided by (used in) operating activities	(402,520)	2,580,592
INVESTING ACTIVITIES
Capital expenditures	(3,639,645)	$ (1,291,915)
Change in restricted cash for investing activities	3,064,730
Net cash used in investing activities	(574,915)	$ (1,291,915)
FINANCING ACTIVITIES
Payments on long-term debt	(478,431)	(300,106)
Change in restricted cash for financing activities	162,264	(2,598)
Net cash used in financing activities	(316,167)	(302,704)
Net increase (decrease) in cash and cash equivalents	(1,293,602)	985,973
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	560,273	$ 2,279,206
Non-cash investing and financing activities:
Financing of capital expenditures via capital lease	1,106,205
Interest paid	$ 668,343	$ 165,513
Income taxes paid

XML

1. Organization

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Nature of Operations.  We are primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Texas (the “Nixon Facility”).  As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own and operate pipeline assets and have leasehold interests in oil and gas properties. See “Note (4) Business Segment Information” of this Quarterly Report for further discussion of our business segments.

Structure and Management. We were formed as a Delaware corporation in 1986.  We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the “Operating Agreement”).  Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer and President of Blue Dolphin, as well as a majority owner of LEH.   See “Note (8) Accounts Payable, Related Party,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” of this Quarterly Report for additional disclosures related to the Operating Agreement, Jonathan Carroll, and LEH.

Our operations are conducted through the following operating subsidiaries:

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

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

• Blue Dolphin Pipe Line Company, a Delaware corporation;

• Blue Dolphin Petroleum Company, a Delaware corporation; and

• Blue Dolphin Services Co., a Texas corporation.

See "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Owned and Leased Assets” in our Annual Report for the fiscal year ended December 31, 2015 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) for additional information regarding our operating subsidiaries.

Operating Risks.  We had cash and cash equivalents of $560,273 and $1,853,875 at March 31, 2016 and December 31, 2015, respectively. We currently rely on our profit share under the Joint Marketing Agreement and LEH to fund our working capital requirements.  During months in which we receive no profit share under the Joint Marketing Agreement, LEH may, but is not required to, fund our working capital requirements. There can be no assurances that LEH will continue to fund our working capital requirements.

As of March 31, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign Bank, a Texas state bank (“Sovereign”). We are currently making our scheduled monthly payments in accordance with the terms and conditions of the loan agreements. See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to Sovereign, our long-term debt, and financial covenant violations.

In addition to the Joint Marketing Agreement, we are party to a variety of contracts and agreements with Genesis Energy, LLC “(Genesis”) and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice.  These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain these relationships or our relationships are not on good terms, it could have a material adverse effect on our operations, liquidity and financial condition. See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to Genesis, the Joint Marketing Agreement, and the Crude Supply Agreement.

We believe that our cash flows from operations, existing cash and cash equivalents, and proceeds from credit facilities will be sufficient to support our operations and capital expenditures for the next 12 to 18 months. However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and the financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

XML

2. Basis of Presentation

3 Months Ended

Mar. 31, 2016

Disclosure Text Block [Abstract]

Basis of Presentation

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation.  In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading.

The consolidated balance sheet at December 31, 2015 has been derived from the audited financial statements at that date.  The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report.  Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016, or for any other period.

XML

3. Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management who is responsible for its integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.

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

Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents totaled $560,273 and $1,853,875 at March 31, 2016 and December 31, 2015, respectively.

Restricted Cash. Restricted cash, current totaled $3,013,035 and $3,175,299 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, noncurrent totaled $12,551,748 and $15,616,478 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, current primarily represents: (i) a construction contingency account under which Sovereign will fund contingencies and (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement.  Restricted cash, noncurrent represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to loan agreements with Sovereign.

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 on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary.  Allowance for doubtful accounts totaled $0 and $139,868 at March 31, 2016 and December 31, 2015, respectively.

Inventory. The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals.  Inventory reflected for crude oil and condensate is nominal and represents line fill.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.  If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold.  See “Note (6) Inventory” of this Quarterly Report for additional disclosures related to our inventory.

Derivatives. We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy.  Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.

Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations.  Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.

See “Note (17) Fair Value Measurement” and “Note (18) Inventory Risk Management” of this Quarterly Report for additional disclosures related to derivatives.

Property and Equipment.

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement.  Management expects to continue making improvements to the Nixon Facility based on technological advances.

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets at March 31, 2016 or December 31, 2015.

Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment.  Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our oil and gas properties had no production during the three months ended March 31, 2016 and 2015.  All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired at December 31, 2012.

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

See “Note (7) Property, Plant and Equipment, Net” of this Quarterly Report for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.

Intangibles – Other. We have an intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015.

Revenue Recognition.

Refined Petroleum Products Revenue. We sell jet fuel in nearby markets, and our intermediate products, including LPG, naphtha, HOBM, and AGO, to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

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

Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.

Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.

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

Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the “Purchase Agreement”) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of retiring certain of the assets. See “Part I, Business -- Governmental Regulation -- Offshore Safety and Environmental Oversight – Decommissioning Requirements” of our Annual Report for a discussion related to supplemental pipeline bonds.

Income Taxes. We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.

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

See “Note (15) Income Taxes” of this Quarterly Report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized.  Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.

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

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

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

See “Note (11) Asset Retirement Obligations” of this Quarterly Report for additional information related to our AROs.

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

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases.  See “Note (16) Earnings Per Share” for additional information related to EPS.

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

Treasury Stock. We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets.  See “Note (12) Treasury Stock” of this Quarterly Report for additional disclosures related to treasury stock.

New Accounting Pronouncement.  In April 2015, FASB issued ASU 2015-03, Imputation of Interest (Topic 835):  Simplifying the Presentation of Debt Issuance Costs.  This guidance requires debt issue costs to be presented as an offset to their related debt.  Effective January 1, 2015, we adopted this accounting pronouncement.  Accordingly, our consolidated balance sheets at March 31, 2016 and December 31, 2015 as reflected within this Quarterly Report have been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.

New Pronouncements Issued But Not Yet Effective. FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content.  The following are recently issued, but not yet effective, accounting standards that may have an effect on our consolidated financial position, results of operations, or cash flows:

ASU 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent.  Current GAAP requires deferred tax liabilities and assets to be separated into current and noncurrent.  ASU 2015-17 is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period, and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented.  We anticipate utilizing the majority of our current deferred tax assets prior to the effective date of ASU 2015-17.  We do not anticipate adoption of this guidance to have a material effect on our consolidated balance sheets.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market.  Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin.  Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value.  Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards.  For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.  ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern for a one year period subsequent to the date of the financial statements.  An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In May 2014, FASB issued ASU 2014-09, which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year.  The effective date for public business entities is annual reporting periods beginning after December 15, 2017.  Public business entities would apply the new revenue standard to interim reporting periods after December 15, 2017.  As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods.  This represents a one-year deferral from the original effective date.  The new effective date guidance allows early adoption for all entities as of the original effective date (December 15, 2016). In March 2016, FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), which clarifies the implementation guidance on principal versus agent considerations. When another party, along with the entity, is involved in providing a good or a service to a customer, the entity must determine whether the nature of its promise is to provide that good or service to the customer (e.g., entity as principal) or to arrange for the good or service to be provided to the customer by the other party (e.g., entity as agent).  Such determination is based upon whether the entity controls the good or the service before it is transferred to the customer.  We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, and ASU 2016-08, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.

Other new pronouncements issued but not effective until after March 31, 2016 are not expected to have a material impact on our financial position, results of operations or liquidity.

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4. Business Segment Information

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Business Segment Information

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

Business segment information for the three months ended March 31, 2016 and 2015 (and at March 31, 2016 and 2015), was as follows:

	Three Months Ended March 31, 2016												Three Months Ended March 31, 2015
	Segment												Segment
	Refinery Operations			Pipeline Transportation			Corporate & Other			Total			Refinery Operations			Pipeline Transportation			Corporate & Other			Total
Revenue from operations	$	31,484,624		$	27,652		$	-		$	31,512,276		$	61,353,954		$	38,395		$	-		$	61,392,349
Less: cost of operations(1)		(34,422,853	)		(122,128	)		(224,775	)		(34,769,756	)		(52,259,470	)		(53,912	)		(408,048	)		(52,721,430	)
Other non-interest income(2)		-			130,665			-			130,665			-			62,500			-			62,500
Adjusted EBITDA		(2,938,229	)		36,189			(224,775	)		(3,126,815	)		9,094,484			46,983			(408,048	)		8,733,419
Less:  JMA Profit Share(3)		671,092			-			-			671,092			(2,438,637	)		-			-			(2,438,637	)
EBITDA	$	(2,267,137	)	$	36,189		$	(224,775	)				$	6,655,847		$	46,983		$	(408,048	)
Depletion, depreciation and amortization											(440,453	)											(399,231	)
Interest expense, net											(418,809	)											(204,569	)
Income (loss) before income taxes											(3,314,985	)											5,690,982
Income tax benefit (expense)											1,165,901												(1,989,618	)
Net income (loss)										$	(2,149,084	)										$	3,701,364
Capital expenditures	$	3,639,645		$	-		$	-		$	3,639,645		$	1,291,915		$	-		$	-		$	1,291,915
Identifiable assets	$	87,970,266		$	2,026,778		$	5,211,165		$	95,208,209		$	53,361,470		$	2,923,368		$	4,355,252		$	60,640,090

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue.  See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” of this Quarterly Report for further discussion related to FLNG.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

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5. Prepaid Expenses and Other Current Assets

3 Months Ended

Mar. 31, 2016

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

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
Unrealized hedging gains	$	1,190,640	$	-
Prepaid insurance		155,782		315,120
Prepaid listing fees		11,250		-
Prepaid related party operating expenses		-		624,570
	$	1,357,672	$	939,690

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6. Inventory

3 Months Ended

Mar. 31, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
HOBM	$	8,327,943	$	5,007,576
Jet fuel		5,547,597		2,045,784
Naphtha		427,496		309,850
AGO		408,152		278,278
Chemicals		101,063		122,777
Crude oil and condensate		19,041		19,041
Propane		11,212		17,860
LPG mix		8,463		7,152
	$	14,850,967	$	7,808,318

Product mix and inventory levels may fluctuate from one period to the next to capture market opportunities.  At March 31, 2016, our diesel and jet fuel inventory increased intentionally compared to December 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

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7. Property, Plant and Equipment, Net

3 Months Ended

Mar. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property, plant and equipment, net, for the periods indicated consisted of the following:

	March 31,			December 31,
	2016			2015
Refinery and facilities	$	43,046,528		$	40,195,928
Pipelines and facilities		2,127,207			2,127,207
Onshore separation and handling facilities		325,435			325,435
Land		602,938			602,938
Other property and equipment		652,795			644,795
		46,754,903			43,896,303
Less:  Accumulated depletion, depreciation, and amortization		(6,674,613	)		(6,234,161	)
		40,080,290			37,662,142
Construction in progress		13,066,919			11,179,670
	$	53,147,209		$	48,841,812

We capitalize interest cost incurred on funds used to construct property, plant, and equipment.  The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s useful life.  Interest cost capitalized was $954,134 and $556,032 at March 31, 2016 and December 31, 2015, respectively.

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8. Accounts Payable, Related Party

3 Months Ended

Mar. 31, 2016

Payables and Accruals [Abstract]

Accounts Payable, Related Party

Accounts payable, related party totaled $408,556 and $300,000 at March 31, 2016 and December 31, 2015, respectively.  Accounts payable, related party consisted of reimbursements and fees under the Operating Agreement, off-site storage tank leasing expense, and guaranty fee expense related to certain of our long-term debt.

Short-Term Tank Lease Agreement.  We utilize a short-term tank lease agreement with Ingleside Crude, LLC (“Ingleside”) to meet periodic additional storage needs.  The Tank Lease Agreement had an initial term of 30 days and automatically renews for 30 day periods. The parties may terminate the Tank Lease Agreement upon 30 days written notice. Ingleside is a related party of LEH and Jonathan Carroll.

At March 31, 2016 and December 31, 2015, accounts payable, related party to Ingleside totaled $172,389 and $300,000, respectively.  For the three months ended March 31, 2016 and 2015, fees to Ingleside totaled $275,000 (approximately $0.23 per bbl of throughput) and $0, respectively, and were reflected as refinery operating expenses in our consolidated statements of operations.

Operating Agreement.  LEH manages and operates all of our properties pursuant to the Operating Agreement.  LEH, our controlling shareholder, owns approximately 81% of our Common Stock.  Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party.

For services rendered, LEH receives reimbursements and fees as follows:

• Reimbursements. For management and operation of all properties excluding the Nixon Facility, LEH is reimbursed at cost for all reasonable expenses incurred while performing the services.  Unsettled reimbursements to LEH are reflected within prepaid expenses and other current assets or accounts payable, related party in our consolidated balance sheets.

At March 31, 2016, accounts payable, related party to LEH totaled $77,836.  At December 31, 2015, prepaid related party operating expenses to LEH totaled $624,570.  See “Note (5) Prepaid Expenses and Other Current Assets” of this Quarterly Report for additional disclosures with respect to related party expenses.

• Fees. For management and operation of the Nixon Facility, LEH receives fees: (i) in the form of weekly payments from GEL TEX Marketing, LLC (“GEL”) not to exceed $750,000 per month, (ii) $0.25 for each bbl processed at the Nixon Facility up to a maximum quantity of 10,000 bbls per day determined on a monthly basis, and (iii) $2.50 for each bbl processed at the Nixon Facility in excess of 10,000 bbls per day determined on a monthly basis.  Amounts expensed as fees are reflected as refinery operating expenses in our consolidated statements of operations.

For the three months ended March 31, 2016 and 2015, fees to LEH totaled $3,162,017 (approximately $2.67 per bbl of throughput) and $2,880,971 (approximately $2.71 per bbl of throughput), respectively, and were reflected as refinery operating expenses in our consolidated statements of income.

Guaranty Fees Agreements.  As a condition of certain of our long-term debt, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loans.  For his personal guarantee, Jonathan Carroll receives fees pursuant to Guaranty Fee Agreements. At March 31, 2016 and December 31, 2015, accounts payable, related party to Jonathan Carroll totaled $158,331 and $0, respectively.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for further discussion related to the Guaranty Fee Agreements.

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9. Long-Term Debt, Net

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt, Net

Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, consisted of the following for the periods indicated:

	March 31, 2016								December 31, 2015
			Debt Issue			Long-Term					Debt Issue			Long-Term
	Principal		Costs			Debt, Net			Principal		Costs			Debt, Net
First Term Loan Due 2034		24,464,586		(1,601,787	)		22,862,799			24,643,081		(1,623,810	)		23,019,271
Second Term Loan Due 2034		9,926,704		(757,572	)		9,169,132			10,000,000		(767,672	)		9,232,328
Notre Dame Debt		1,300,000		-			1,300,000			1,300,000		-			1,300,000
Term Loan Due 2017		739,974		-			739,974			924,969		-			924,969
Capital Leases		262,972		-			262,972			304,618		-			304,618
	$	36,694,236	$	(2,359,359	)	$	34,334,877		$	37,172,668	$	(2,391,482	)	$	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion							(32,942,090	)							(1,934,932	)
						$	1,392,787							$	32,846,254

Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) consisted of the following for the periods indicated:

	March 31,			December 31,
	2016			2015
Notre Dame Debt		1,534,661			1,482,801
First Term Loan Due 2034		45,894			34,883
Second Term Loan Due 2034		34,630			39,193
Term Loan Due 2017		4,779			4,779
Capital Leases		2,255			2,612
	$	1,622,219		$	1,564,268
Less:  Interest payable, current portion		(87,558	)		(81,467	)
	$	1,534,661		$	1,482,801

First Term Loan Due 2034. LE entered into a Loan and Security Agreement with Sovereign in June 2015, as administrative agent and lender pursuant to a term loan in the principal amount of $25.0 million (the “First Term Loan Due 2034”).  The First Term Loan Due 2034 matures in June 2034, has current monthly payments of principal and interest of $188,409, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the First Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash and restricted cash, noncurrent in our consolidated balance sheets.

As of March 31, 2016, LE was in violation of the debt service coverage ratio and the current ratio financial covenants under the First Term Loan Due 2034. Accordingly, the First Term Loan Due 2034 has been classified within the current portion of long-term debt, on our consolidated balance sheets.  See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the First Term Loan Due 2034.

As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LE entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the First Term Loan Due 2034.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $122,633 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.  LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due 2034.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

Proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed to American First National Bank under the Refinery Note.  Remaining proceeds are being used primarily to construct new petroleum storage tanks. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a $1.0 million payment reserve account held by Sovereign, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll.  The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.

Second Term Loan Due 2034. LRM entered into a Loan and Security Agreement with Sovereign in December 2015, as administrative agent and lender pursuant to a term loan in the principal amount of $10.0 million (the “Second Term Loan Due 2034”).  The Second Term Loan Due 2034 matures in December 2034, has current monthly payments of principal and interest of $74,111, and accrues interest at a rate based on the Wall Street Journal Prime Rate plus 2.75%.  Pursuant to a construction rider in the Second Term Loan Due 2034, proceeds available for use were placed in a disbursement account whereby Sovereign makes payments for construction related expenses. Amounts held in the disbursement account are reflected as restricted cash and restricted cash, noncurrent in our consolidated balance sheets.

As of March 31, 2016, LRM was in violation of the debt service coverage ratio and the current ratio financial covenants under the Second Term Loan Due 2034. Accordingly, the Second Term Loan Due 2034 has been classified within the current portion of long-term debt on our consolidated balance sheets.  See “Note (1) Organization – Operating Risks” of this Quarterly Report for additional disclosures related to Sovereign and the Second Term Loan Due 2034.

As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan P. Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Second Term Loan Due 2034.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,747 and $0, respectively.  Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.   LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

Proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan to Sovereign in the amount of $3.0 million.  Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the Nixon Facility and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of Tanks 62, 63, and 80, with respect to which Sovereign will have a second priority lien in such leases subordinate to a prior lien granted by LRM to Sovereign to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents.  The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type.

Notre Dame Debt. LE entered into a loan with Notre Dame Investors, Inc. as evidenced by a Promissory Note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt matures in January 2018, and accrues interest at a rate of 16.00%.

The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE.  There are no financial maintenance covenants associated with the Notre Dame Debt. Pursuant to a Subordination Agreement dated June 2015, the holder of the Notre Dame Debt agreed to subordinate any security interest and liens on the Nixon Facility, as well as its right to payments, in favor of Sovereign as holder of the First Term Loan Due 2034.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for additional disclosures related to the Genesis Agreements.

Term Loan Due 2017. LRM entered into a Loan and Security Agreement with Sovereign in May 2014, for a term loan facility in the principal amount of $2.0 million (the “Term Loan Due 2017”).  The Term Loan Due 2017 was amended in March 2015, pursuant to a Loan Modification Agreement (the “March Loan Modification Agreement”).  Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due date was extended to March 2017.  Pursuant to the March Loan Modification Agreement, the monthly payment due under the Term Loan Due 2017 is $61,665 plus interest.

As a condition of the Term Loan Due 2017, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan.  For his personal guarantee, LRM entered into a Guaranty Fee Agreement with Jonathan Carroll whereby he receives a fee equal to 2.00% per annum, paid monthly, of the outstanding principal balance owed under the Term Loan Due 2017.  For the three months ended March 31, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $4,008 and $0, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units.  The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and certain assets of LEH.  See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to LEH and Jonathan Carroll.

Capital Leases. LRM entered into a 36 month build-to-suit capital lease in August 2014 for the purchase of new boiler equipment for the Nixon Facility.  The equipment, which was delivered in December 2014, was added to construction in progress.  Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease, which requires a quarterly payment in the amount of $44,258, is guaranteed by Blue Dolphin.

A summary of equipment held under long-term capital leases for the periods indicated follows:

	March 31,		December 31,
	2016		2015
Boiler equipment	$	538,598	$	538,598
Less:  accumulated depreciation		-		-
	$	538,598	$	538,598

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10. Accrued Expenses and Other Current Liabilities

3 Months Ended

Mar. 31, 2016

Disclosure Text Block Supplement [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities for the periods indicated consisted of the following: 

	March 31,		December 31,
	2016		2015
Excise and income taxes payable	$	1,080,083	$	1,290,101
Unearned revenue		315,000		781,859
Other payable		131,115		157,714
Board of director fees payable		98,929		86,429
Insurance		64,390		103,024
Property taxes		29,678		-
Genesis JMA Profit Share payable		-		388,364
Unrealized hedging loss		-		183,400
	$	1,719,195	$	2,990,891

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11. Asset Retirement Obligations

3 Months Ended

Mar. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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

Pipelines and Facilities and Oil and Gas Properties.  We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities assets, as well as the plugging and abandonment of our oil and gas properties.  We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Plugging and abandonment costs are recorded during the period incurred or as information becomes available to substantiate actual and/or probable costs.

Changes to our ARO liability for the periods indicated were as follows:

	March 31,			December 31,
	2016			2015
Asset retirement obligations, at the beginning of the period	$	1,985,864		$	1,866,770
New asset retirement obligations and adjustments		-			49
Liabilities settled		(36,043	)		(92,330	)
Accretion expense		28,186			211,375
		1,978,007			1,985,864
Less:  asset retirement obligations, current portion		(38,644	)		(38,644	)
Long-term asset retirement obligations, at the end of the period	$	1,939,363		$	1,947,220

Liabilities settled represents amounts paid for plugging and abandonment costs against the asset’s ARO liability and are reflected in our consolidated balance sheets.  At March 31, 2016 and December 31, 2015, we recognized $36,043 and $92,330, respectively, in liabilities settled. Abandonment expense represents amounts paid for plugging and abandonment costs that exceed the asset’s ARO liability and are reflected in our consolidated statements of operations.  For the three months ended March 31, 2016 and 2015, we recognized $0 in abandonment expense.

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12. Treasury Stock

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Treasury Stock

At March 31, 2016 and December 31, 2015, we had 150,000 shares of treasury stock.

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13. Concentration of Risk

3 Months Ended

Mar. 31, 2016

Risks and Uncertainties [Abstract]

Concentration of Risk

Bank Accounts. Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the U.S., the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor.  We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $15,507,858 and $19,594,883 at March 31, 2016 and December 31, 2015, respectively.

Key Supplier. Under the Crude Oil and Supply Throughput Services Agreement dated in August 2011 (the “Crude Supply Agreement”), GEL is our exclusive supplier of crude oil and condensate.  We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL.  The initial term was to expire in August 2014.  However, in October 2013, we entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam Services, Inc. (“Milam”) (the “October 2013 Letter Agreement”), effective in October 2013.  In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice.

Significant Customers. We routinely assess the financial strength of our customers and have not experienced significant write-downs in our accounts receivable balances.  As a result, we believe that our accounts receivable credit risk exposure is limited.  For the three months ended March 31, 2016, we had 5 customers that accounted for approximately 75.4% of our refined petroleum products sales.  These 5 customers represented approximately $2.3 million in accounts receivable at March 31, 2016.  For the three months ended March 31, 2015, we had 3 customers that accounted for approximately 67% of our refined petroleum products sales.  These 3 customers represented approximately $4.1 million in accounts receivable at March 31, 2015.

Refined Petroleum Product Sales. All of our refined petroleum products are currently sold in the U.S. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016				2015
LPG mix	$	250,547	0.8	%	$	57,308	0.0	%
Naphtha		9,025,521	28.9	%		13,416,199	22.0	%
Jet fuel		8,506,313	27.3	%		16,519,503	27.1	%
HOBM		3,163,495	10.1	%		17,409,079	28.5	%
Reduced Crude		3,245,807	10.4	%		-	0.0	%
AGO		7,001,454	22.5	%		13,664,973	22.4	%
	$	31,193,137	100.0	%	$	61,067,062	100.0	%

For the three months ended March 31, 2016 we sold less bbls of diesel and jet fuel as a result of intentionally increasing inventory compared to the three months ended March 31, 2015 to fulfill anticipated orders from a large new customer, seasonal jet fuel demand, and in anticipation of the opening of the Mexican diesel market to private companies.

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14. Leases

3 Months Ended

Mar. 31, 2016

Leases, Operating [Abstract]

Leases

Our company headquarters is located in downtown Houston, Texas.  We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10 year term expiring in 2017, includes free rent periods and escalating rent payment provisions, and requires payment of a portion of related actual operating expenses.  Rent expense is recognized on a straight-line basis.  For the three months ended March 31, 2016 and 2015, rent expense totaled $29,857 and $25,829, respectively.

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15. Income Taxes

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Tax Benefit (Expense).  Income tax benefit (expense) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016		2015
Current:
Federal	$	-	$	(99,281	)
State		-		(82,853	)
Deferred:
Federal		1,165,901		(1,807,484	)
	$	1,165,901	$	(1,989,618	)

The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of TMT make it similar to an income tax.  Accordingly, TMT is treated as an income tax for financial reporting purposes.

Deferred Income Taxes.  Deferred income tax balances reflect the effects of temporary differences between the carrying amounts of assets and liabilities and their tax bases, as well as from NOL carryforwards.  We state those balances at the enacted tax rates we expect will be in effect when taxes are actually paid.  NOL carryforwards and deferred tax assets represent amounts available to reduce future taxable income.

NOL Carryforwards.  Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). For income tax purposes, we experienced ownership changes in 2005, in connection with a series of private placements, and in 2012, as a result of a reverse acquisition, that limit the use of pre-change NOL carryforwards to offset future taxable income.  In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. The 2012 ownership change will subject approximately $18.8 million in NOL carryforwards that were generated prior to the ownership change to an annual use limitation of $638,196 per year.  Unused portions of the annual use limitation amount may be used in subsequent years.  As a result of the annual use limitation, approximately $6.7 million in NOL carryforwards that were generated prior to the 2012 ownership change will expire unused.  NOL carryforwards that were generated after the 2012 ownership change are not subject to an annual use limitation under IRC Section 382 and may be used in addition to available amounts of NOL carryforwards generated prior to the ownership change.

NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused as a result of the IRC Section 382 limitation):

	Net Operating Loss Carryforward
	Pre-Ownership			Post-Ownership			Total
Balance at December 31, 2014	$	10,766,912		$	12,145,789		$	22,912,701
Net operating loss carryforwards utilized		(1,152,463	)		(2,528,848	)		(3,681,311	)
								-
Balance at December 31, 2015		9,614,449			9,616,941			19,231,390
Net operating losses		-			5,871,350			5,871,350
Balance at March 31, 2016	$	9,614,449		$	15,488,291		$	25,102,740

Deferred Tax Assets and Liabilities.  At March 31, 2016 and December 31, 2015, approximately $4.8 million and $3.6 million, respectively, of net deferred tax assets remained available for future use.  Significant components of deferred tax assets and liabilities for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	10,805,253		$	8,815,794
Start-up costs (Nixon Facility)		1,476,365			1,510,699
Asset retirement obligations liability/deferred revenue		711,507			717,723
Unrealized hedges		-			62,356
AMT credit and other		219,814			302,086
Total deferred tax assets		13,212,939			11,408,658
Deferred tax liabilities:
Fair market value adjustments		(46,116	)		(46,116	)
Unrealized hedges		(404,818	)		-
Basis differences in property and equipment		(5,718,545	)		(5,484,983	)
Total deferred tax liabilities		(6,169,479	)		(5,531,099	)
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

Deferred tax assets (liabilities) on a current and noncurrent basis for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Current deferred tax assets	$	4,845,465		$	3,486,746
Noncurrent deferred tax assets, net		2,197,995			2,390,813
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

Valuation Allowance. As of each reporting date, management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets.  As of March 31, 2016 and December 31, 2015, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $4.8 million and $3.6 million, respectively, were realizable, and as a result, reflected a valuation allowance accordingly.

Uncertain Tax Positions. We have adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the three months ended March 31, 2016 and 2015. Our federal income tax returns are subject to examination by the Internal Revenue Service for tax years ending December 31, 2012, or after and by the state of Texas for tax years ending December 31, 2011, or after.  We believe there are no uncertain tax positions for both federal and state income taxes.

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16. Earnings Per Share

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share

A reconciliation between basic and diluted income per share for the periods indicated was as follows:

	Three Months Ended March 31,
	2016			2015
Net income (loss)	$	(2,149,084	)	$	3,701,364
Basic and diluted income per share	$	(0.21	)	$	0.35
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,457,794			10,449,444

Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding.  Diluted EPS for the three months ended March 31, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

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17. Fair Value Measurement

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurement

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

Generally accepted accounting principles establish a framework for measuring the fair value.  That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The fair value hierarchy consists of the following three levels:

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

The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at December 31, 2015 and 2014 due to their short-term maturities. The fair value of our long-term debt, net including the current portion at March 31, 2016 and December 31, 2015 was $34,334,877 and $34,781,186, respectively. The fair value of our debt was determined using a Level 3 hierarchy.

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 and the basis for the measurement:

			Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at March 31, 2016		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	1,190,640	$	1,190,640	$	-	$	-

				Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015			Quoted Prices in Active Markets  for Identical Assets or Liabilities (Level 1)			Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(183,400	)	$	(183,400	)	$	-	$	-

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

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18. Inventory Risk Management

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Inventory Risk Management

Management periodically determines whether to maintain, increase, or decrease inventory levels based on various factors, including the crude pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows.  Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled by Genesis with cash.

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

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

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

As of March 31, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in bbls):

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2016		2017		2018
Refined petroleum products and crude oil -
net short positions		460,000		-		-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2016 and December 31, 2015:

		Fair Value
		March 31,		December 31,
Asset Derivatives	Balance Sheets Location	2016		2015
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	1,190,640	$	(183,400	)

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended March 31,
Derivatives	Statements of Operations Location	2016			2015
Commodity contracts	Cost of refined products sold	$	(492,528	)	$	927,584

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19. Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Operating Agreement. See “Note (8) Accounts Payable, Related Party” of this Quarterly Report for additional disclosures related to the Operating Agreement.

Genesis Agreements. We were previously subject to three agreements with Genesis and its affiliates.  Under the Construction and Funding Agreement, Milam committed funding for the Nixon Facility’s start-up refurbishment.  Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service.  As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, we now receive up to 80% of the Gross Profits as our Profit Share under the Joint Marketing Agreement, which is described below.  Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows:

Crude Supply Agreement. Under the Crude Supply Agreement, GEL is our exclusive supplier of crude oil and condensate. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to us pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described above. In addition, GEL has a first right of refusal to use three petroleum storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years expiring in August 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 2019, unless sooner terminated by GEL with 180 days prior written notice; and

Joint Marketing Agreement. Under the Joint Marketing Agreement, we, together with GEL, jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. GEL is responsible for all product transportation scheduling; we are responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same.  All payments for the sale of output produced at the Nixon Facility are made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement).  As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, certain aspects related to the distribution of Gross Profits under the Joint Marketing Agreement no longer apply.  Key applicable provisions are as follows:

- We are entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees, if incurred, not to exceed $50,000 per month.  We assigned our rights to weekly payments and reimbursement of accounting fees under the Joint Marketing Agreement to LEH pursuant to the Operating Agreement. If Gross Profits are insufficient to cover Operations Payments, then GEL may: (i) reduce Operations Payments by an amount representing the difference between the Operations Payments and the Gross Profits for such monthly period, or (ii) provide the Operations Payments with such Operations Payments being considered deficit amounts owing to GEL.  If Gross Profits are negative, then we are not entitled to receive Operations Payments and GEL may recoup any losses sustained by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated; and

- GEL is entitled to receive an administrative fee in the amount of $150,000 per month relating to the performance of its obligations under the Joint Marketing Agreement (the “Performance Fee”). GEL shall be paid 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share and we shall be paid 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and us in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the our Profit Share.  The GEL Profit Share plus the Performance Fee are collectively referred to in this Quarterly Report as the Joint Marketing Agreement Profit Share (the “JMA Profit Share”).

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

Pursuant to a Letter Agreement Regarding Subordination of GEL Transaction Documents dated in June 2015, we, among other things, assigned our rights to payments under the Crude Supply Agreement and Joint Marketing Agreement as collateral in favor of Sovereign Bank, a Texas state bank (“Sovereign”), as lender and lienholder pursuant to that certain Loan and Security Agreement between us and Sovereign dated in June 2015 in the principal amount of $25.0 million (the “Term Loan Due 2034”).  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for further discussion related to the Term Loan Due 2034.

LE has a dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement.  On May 2, 2016, GEL filed a lawsuit in Texas state court in Harris County. On May 13, 2016, LE filed a Demand for Arbitration with the American Arbitration Association to bring the dispute to resolution. We are not presently able to reasonably estimate the outcome related to the lawsuit and as such, have not recorded a liability in the consolidated balance sheets.

FLNG Master Easement Agreement. Pursuant to a Master Easement Agreement dated in December 2013, we provide FLNG Land II, Inc., a Delaware corporation (“FLNG”) with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across certain of our property to certain property of FLNG (the “Access Easement”) and (ii) a pipeline easement and right of way across certain of our property to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”). Under the agreement, FLNG will make payments to us in the amount of $500,000 in October of each year through 2019.  Thereafter, FLNG will make payments to us in the amount of $10,000 in October of each year for so long as FLNG desires to use the Access Easement.

Supplemental Pipeline Bonds. In order to cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, the Bureau of Ocean Energy Management (the “BOEM”) generally requires that lessees and rights-of-way holders demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied, unless the BOEM exempts the lessee or rights-of-way holder from such financial assurance requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by the BOEM.

In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking outlining proposed changes to financial assurance requirements in order to modernize financial assurance and risk management and better address potential costs and liabilities of offshore energy development. Part of the Advanced Notice of Proposed Rulemaking includes the BOEM revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit based model.  Following a public comment period, the BOEM plans to publish a revised notice to lessees in 2016 that will outline new financial assurance requirements.

In August 2015, we received a letter from the BOEM requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. We are currently working with the BOEM to develop a tailored plan to address the financial assurance requirements. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. At March 31, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM.

Financing Agreements. See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to financing agreements.

Nixon Facility Expansion. We have made and continue to make capital and efficiency improvements to the Nixon Facility. As a result, we have incurred and will continue to incur capital expenditures related to these improvements, which include, among other things, facility and land improvements and construction of additional petroleum storage tanks.

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

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

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3. Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Use of Estimates

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

Cash and Cash Equivalents

Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents totaled $560,273 and $1,853,875 at March 31, 2016 and December 31, 2015, respectively.

Restricted Cash

Restricted Cash. Restricted cash, current totaled $3,013,035 and $3,175,299 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, noncurrent totaled $12,551,748 and $15,616,478 at March 31, 2016 and December 31, 2015, respectively. Restricted cash, current primarily represents: (i) a construction contingency account under which Sovereign will fund contingencies and (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement.  Restricted cash, noncurrent represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks.  See “Note (9) Long-Term Debt, Net” of this Quarterly Report for additional disclosures related to loan agreements with Sovereign.

Accounts Receivable and Allowance for Doubtful Accounts

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 on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary.  Allowance for doubtful accounts totaled $0 and $139,868 at March 31, 2016 and December 31, 2015, respectively.

Inventory

Inventory. The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals.  Inventory reflected for crude oil and condensate is nominal and represents line fill.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.  If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold.  See “Note (6) Inventory” of this Quarterly Report for additional disclosures related to our inventory.

Derivatives

Derivatives. We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy.  Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.

Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations.  Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.

See “Note (17) Fair Value Measurement” and “Note (18) Inventory Risk Management” of this Quarterly Report for additional disclosures related to derivatives.

Property and Equipment

Property and Equipment.

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement.  Management expects to continue making improvements to the Nixon Facility based on technological advances.

We record refinery and facilities at cost less any adjustments for depreciation or impairment.  Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations.  For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service.  We did not record any impairment of our refinery and facilities assets at March 31, 2016 or December 31, 2015.

Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment.  Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our oil and gas properties had no production during the three months ended March 31, 2016 and 2015.  All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired at December 31, 2012.

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

See “Note (7) Property, Plant and Equipment, Net” of this Quarterly Report for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.

Intangibles - Other

Intangibles – Other. We have an intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015.

Revenue Recognition

Revenue Recognition.

Refined Petroleum Products Revenue. We sell jet fuel in nearby markets, and our intermediate products, including LPG, naphtha, HOBM, and AGO, to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

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

Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.

Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.

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

Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the “Purchase Agreement”) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of retiring certain of the assets. See “Part I, Business -- Governmental Regulation -- Offshore Safety and Environmental Oversight – Decommissioning Requirements” of our Annual Report for a discussion related to supplemental pipeline bonds.

Income Taxes

Income Taxes. We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current period and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns.  Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse.  

As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets.  Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards.  When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets.

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

See “Note (15) Income Taxes” of this Quarterly Report for further information related to income taxes.

Impairment or Disposal of Long-Lived Assets

Impairment or Disposal of Long-Lived Assets. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized.  Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.

Asset Retirement Obligations

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

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

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

See “Note (11) Asset Retirement Obligations” of this Quarterly Report for additional information related to our AROs.

Computation of Earnings Per Share

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

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases.  See “Note (16) Earnings Per Share” for additional information related to EPS.

Stock-Based Compensation

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

Treasury Stock

Treasury Stock. We account for treasury stock under the cost method.  When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets.  See “Note (12) Treasury Stock” of this Quarterly Report for additional disclosures related to treasury stock.

New Accounting Pronouncement

New Accounting Pronouncement.  In April 2015, FASB issued ASU 2015-03, Imputation of Interest (Topic 835):  Simplifying the Presentation of Debt Issuance Costs.  This guidance requires debt issue costs to be presented as an offset to their related debt.  Effective January 1, 2015, we adopted this accounting pronouncement.  Accordingly, our consolidated balance sheets at March 31, 2016 and December 31, 2015 as reflected within this Quarterly Report have been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.

New Pronouncements Issued but Not Yet Effective

New Pronouncements Issued But Not Yet Effective. FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content.  The following are recently issued, but not yet effective, accounting standards that may have an effect on our consolidated financial position, results of operations, or cash flows:

ASU 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent.  Current GAAP requires deferred tax liabilities and assets to be separated into current and noncurrent.  ASU 2015-17 is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period, and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented.  We anticipate utilizing the majority of our current deferred tax assets prior to the effective date of ASU 2015-17.  We do not anticipate adoption of this guidance to have a material effect on our consolidated balance sheets.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market.  Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin.  Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value.  Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.  Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards.  For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years.  ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern for a one year period subsequent to the date of the financial statements.  An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In May 2014, FASB issued ASU 2014-09, which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year.  The effective date for public business entities is annual reporting periods beginning after December 15, 2017.  Public business entities would apply the new revenue standard to interim reporting periods after December 15, 2017.  As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods.  This represents a one-year deferral from the original effective date.  The new effective date guidance allows early adoption for all entities as of the original effective date (December 15, 2016). In March 2016, FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), which clarifies the implementation guidance on principal versus agent considerations. When another party, along with the entity, is involved in providing a good or a service to a customer, the entity must determine whether the nature of its promise is to provide that good or service to the customer (e.g., entity as principal) or to arrange for the good or service to be provided to the customer by the other party (e.g., entity as agent).  Such determination is based upon whether the entity controls the good or the service before it is transferred to the customer.  We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, and ASU 2016-08, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.

Other new pronouncements issued but not effective until after March 31, 2016 are not expected to have a material impact on our financial position, results of operations or liquidity.

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4. Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Business segment reporting

Business segment information for the three months ended March 31, 2016 and 2015 (and at March 31, 2016 and 2015), was as follows:

	Three Months Ended March 31, 2016												Three Months Ended March 31, 2015
	Segment												Segment
	Refinery Operations			Pipeline Transportation			Corporate & Other			Total			Refinery Operations			Pipeline Transportation			Corporate & Other			Total
Revenue from operations	$	31,484,624		$	27,652		$	-		$	31,512,276		$	61,353,954		$	38,395		$	-		$	61,392,349
Less: cost of operations(1)		(34,422,853	)		(122,128	)		(224,775	)		(34,769,756	)		(52,259,470	)		(53,912	)		(408,048	)		(52,721,430	)
Other non-interest income(2)		-			130,665			-			130,665			-			62,500			-			62,500
Adjusted EBITDA		(2,938,229	)		36,189			(224,775	)		(3,126,815	)		9,094,484			46,983			(408,048	)		8,733,419
Less:  JMA Profit Share(3)		671,092			-			-			671,092			(2,438,637	)		-			-			(2,438,637	)
EBITDA	$	(2,267,137	)	$	36,189		$	(224,775	)				$	6,655,847		$	46,983		$	(408,048	)
Depletion, depreciation and amortization											(440,453	)											(399,231	)
Interest expense, net											(418,809	)											(204,569	)
Income (loss) before income taxes											(3,314,985	)											5,690,982
Income tax benefit (expense)											1,165,901												(1,989,618	)
Net income (loss)										$	(2,149,084	)										$	3,701,364
Capital expenditures	$	3,639,645		$	-		$	-		$	3,639,645		$	1,291,915		$	-		$	-		$	1,291,915
Identifiable assets	$	87,970,266		$	2,026,778		$	5,211,165		$	95,208,209		$	53,361,470		$	2,923,368		$	4,355,252		$	60,640,090

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses.  Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue.  See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” of this Quarterly Report for further discussion related to FLNG.
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement.  See “Note (19) Commitments and Contingencies – Genesis Agreements” of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

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5. Prepaid Expenses and Other Current Assets (Tables)

3 Months Ended

Mar. 31, 2016

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

Prepaid balances

Prepaid expenses and other current assets for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
Unrealized hedging gains	$	1,190,640	$	-
Prepaid insurance		155,782		315,120
Prepaid listing fees		11,250		-
Prepaid related party operating expenses		-		624,570
	$	1,357,672	$	939,690

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6. Inventory (Tables)

3 Months Ended

Mar. 31, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory for the periods indicated consisted of the following:

	March 31,		December 31,
	2016		2015
HOBM	$	8,327,943	$	5,007,576
Jet fuel		5,547,597		2,045,784
Naphtha		427,496		309,850
AGO		408,152		278,278
Chemicals		101,063		122,777
Crude oil and condensate		19,041		19,041
Propane		11,212		17,860
LPG mix		8,463		7,152
	$	14,850,967	$	7,808,318

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

3 Months Ended

Mar. 31, 2016

Property, Plant and Equipment [Abstract]

Property and equipment

Property, plant and equipment, net, for the periods indicated consisted of the following:

	March 31,			December 31,
	2016			2015
Refinery and facilities	$	43,046,528		$	40,195,928
Pipelines and facilities		2,127,207			2,127,207
Onshore separation and handling facilities		325,435			325,435
Land		602,938			602,938
Other property and equipment		652,795			644,795
		46,754,903			43,896,303
Less:  Accumulated depletion, depreciation, and amortization		(6,674,613	)		(6,234,161	)
		40,080,290			37,662,142
Construction in progress		13,066,919			11,179,670
	$	53,147,209		$	48,841,812

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9. Long-Term Debt, Net (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Long Term Debt

Long-term debt, net, which represents the outstanding principal and interest of long-term debt less associated debt issue costs, consisted of the following for the periods indicated:

	March 31, 2016								December 31, 2015
			Debt Issue			Long-Term					Debt Issue			Long-Term
	Principal		Costs			Debt, Net			Principal		Costs			Debt, Net
First Term Loan Due 2034		24,464,586		(1,601,787	)		22,862,799			24,643,081		(1,623,810	)		23,019,271
Second Term Loan Due 2034		9,926,704		(757,572	)		9,169,132			10,000,000		(767,672	)		9,232,328
Notre Dame Debt		1,300,000		-			1,300,000			1,300,000		-			1,300,000
Term Loan Due 2017		739,974		-			739,974			924,969		-			924,969
Capital Leases		262,972		-			262,972			304,618		-			304,618
	$	36,694,236	$	(2,359,359	)	$	34,334,877		$	37,172,668	$	(2,391,482	)	$	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion							(32,942,090	)							(1,934,932	)
						$	1,392,787							$	32,846,254

Accrued interest related to our long-term debt, net

Accrued interest related to our long-term debt, net (reflected as interest payable, current portion and long-term interest payable, net of current portion in our consolidated balance sheets) consisted of the following for the periods indicated:

	March 31,			December 31,
	2016			2015
Notre Dame Debt		1,534,661			1,482,801
First Term Loan Due 2034		45,894			34,883
Second Term Loan Due 2034		34,630			39,193
Term Loan Due 2017		4,779			4,779
Capital Leases		2,255			2,612
	$	1,622,219		$	1,564,268
Less:  Interest payable, current portion		(87,558	)		(81,467	)
	$	1,534,661		$	1,482,801

Schedule of summary of equipment held under long-term capital leases

A summary of equipment held under long-term capital leases for the periods indicated follows:

	March 31,		December 31,
	2016		2015
Boiler equipment	$	538,598	$	538,598
Less:  accumulated depreciation		-		-
	$	538,598	$	538,598

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10. Accrued Expenses and Other Current Liabilities (Tables)

3 Months Ended

Mar. 31, 2016

Disclosure Text Block Supplement [Abstract]

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities for the periods indicated consisted of the following: 

	March 31,		December 31,
	2016		2015
Excise and income taxes payable	$	1,080,083	$	1,290,101
Unearned revenue		315,000		781,859
Other payable		131,115		157,714
Board of director fees payable		98,929		86,429
Insurance		64,390		103,024
Property taxes		29,678		-
Genesis JMA Profit Share payable		-		388,364
Unrealized hedging loss		-		183,400
	$	1,719,195	$	2,990,891

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11. Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Changes to our ARO liability for the periods indicated were as follows:

	March 31,			December 31,
	2016			2015
Asset retirement obligations, at the beginning of the period	$	1,985,864		$	1,866,770
New asset retirement obligations and adjustments		-			49
Liabilities settled		(36,043	)		(92,330	)
Accretion expense		28,186			211,375
		1,978,007			1,985,864
Less:  asset retirement obligations, current portion		(38,644	)		(38,644	)
Long-term asset retirement obligations, at the end of the period	$	1,939,363		$	1,947,220

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13. Concentration of Risk (Tables)

3 Months Ended

Mar. 31, 2016

Risks and Uncertainties [Abstract]

Percentages of all refined petroleum products sales to total sales

Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016				2015
LPG mix	$	250,547	0.8	%	$	57,308	0.0	%
Naphtha		9,025,521	28.9	%		13,416,199	22.0	%
Jet fuel		8,506,313	27.3	%		16,519,503	27.1	%
HOBM		3,163,495	10.1	%		17,409,079	28.5	%
Reduced Crude		3,245,807	10.4	%		-	0.0	%
AGO		7,001,454	22.5	%		13,664,973	22.4	%
	$	31,193,137	100.0	%	$	61,067,062	100.0	%

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15. Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Income tax benefit (expense)

Income tax benefit (expense) for the periods indicated consisted of the following:

	Three Months Ended March 31,
	2016		2015
Current:
Federal	$	-	$	(99,281	)
State		-		(82,853	)
Deferred:
Federal		1,165,901		(1,807,484	)
	$	1,165,901	$	(1,989,618	)

NOL carryforwards

NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused as a result of the IRC Section 382 limitation):

	Net Operating Loss Carryforward
	Pre-Ownership			Post-Ownership			Total
Balance at December 31, 2014	$	10,766,912		$	12,145,789		$	22,912,701
Net operating loss carryforwards utilized		(1,152,463	)		(2,528,848	)		(3,681,311	)
								-
Balance at December 31, 2015		9,614,449			9,616,941			19,231,390
Net operating losses		-			5,871,350			5,871,350
Balance at March 31, 2016	$	9,614,449		$	15,488,291		$	25,102,740

Deferred tax assets and deferred tax liabilities

Significant components of deferred tax assets and liabilities for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	10,805,253		$	8,815,794
Start-up costs (Nixon Facility)		1,476,365			1,510,699
Asset retirement obligations liability/deferred revenue		711,507			717,723
Unrealized hedges		-			62,356
AMT credit and other		219,814			302,086
Total deferred tax assets		13,212,939			11,408,658
Deferred tax liabilities:
Fair market value adjustments		(46,116	)		(46,116	)
Unrealized hedges		(404,818	)		-
Basis differences in property and equipment		(5,718,545	)		(5,484,983	)
Total deferred tax liabilities		(6,169,479	)		(5,531,099	)
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

Current and noncurrent deferred tax assets (liabilities)

Deferred tax assets (liabilities) on a current and noncurrent basis for the periods indicated were as follow:

	March 31,			December 31,
	2016			2015
Current deferred tax assets	$	4,845,465		$	3,486,746
Noncurrent deferred tax assets, net		2,197,995			2,390,813
Deferred tax assets, net		7,043,460			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
	$	4,773,138		$	3,607,237

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16. Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings per share

A reconciliation between basic and diluted income per share for the periods indicated was as follows:

	Three Months Ended March 31,
	2016			2015
Net income (loss)	$	(2,149,084	)	$	3,701,364
Basic and diluted income per share	$	(0.21	)	$	0.35
Basic and Diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock		10,457,794			10,449,444

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17. Fair Value Measurement (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurement

The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 and the basis for the measurement:

			Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at March 31, 2016		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	1,190,640	$	1,190,640	$	-	$	-

				Fair Value Measurement at March 31, 2016 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015			Quoted Prices in Active Markets  for Identical Assets or Liabilities (Level 1)			Significant Unobservable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity contracts	$	(183,400	)	$	(183,400	)	$	-	$	-

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18. Inventory Risk Management (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

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

	Notional Contract Volumes by Year of Maturity
Inventory positions (futures):	2016		2017		2018
Refined petroleum products and crude oil -
net short positions		460,000		-		-

Fair value amounts of derivative instruments

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2016 and December 31, 2015:

		Fair Value
		March 31,		December 31,
Asset Derivatives	Balance Sheets Location	2016		2015
Commodity contracts	Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$	1,190,640	$	(183,400	)

Effect of derivative instruments

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended March 31,
Derivatives	Statements of Operations Location	2016			2015
Commodity contracts	Cost of refined products sold	$	(492,528	)	$	927,584

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1. Organization (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash and cash equivalents	$ 560,273	$ 1,853,875	$ 2,279,206	$ 1,293,233

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3. Significant Accounting Policies (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 560,273	$ 1,853,875	$ 2,279,206	$ 1,293,233
Restricted cash	3,013,035	3,175,299
Restricted cash, noncurrent	12,551,748	15,616,478
Allowance for doubtful accounts	0	139,868
Trade name	303,346	303,346
Debt issue costs	$ 2,400,000	$ 2,400,000

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4. Business Segment Information (Details) - USD ($)		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Revenue from operations		$ 31,512,276	$ 61,392,349
Income tax benefit (expense)		(1,165,901)	1,989,618
Net income (loss)		(2,149,084)	3,701,364
Refinery Operations [Member]
Revenue from operations		31,484,624	61,353,954
Less: cost of operations	[1]	$ (34,422,853)	$ (52,259,470)
Other non-interest income	[2]
Adjusted EBITDA		$ (2,938,229)	$ 9,094,484
Less: JMA Profit Share	[3]	671,092	(2,438,637)
EBITDA		(2,267,137)	6,655,847
Capital expenditures		3,639,645	1,291,915
Identifiable assets		87,970,266	53,361,470
Pipeline Transportation [Member]
Revenue from operations		27,652	38,395
Less: cost of operations	[1]	(122,128)	(53,912)
Other non-interest income	[2]	130,665	62,500
Adjusted EBITDA		$ 36,189	$ 46,983
Less: JMA Profit Share	[3]
EBITDA		$ 36,189	$ 46,983
Capital expenditures
Identifiable assets		$ 2,026,778	$ 2,923,368
Corporate and Other [Member]
Revenue from operations
Less: cost of operations	[1]	$ (224,775)	$ (408,048)
Other non-interest income	[2]
Adjusted EBITDA		$ (224,775)	$ (408,048)
Less: JMA Profit Share	[3]
EBITDA		$ (224,775)	$ (408,048)
Capital expenditures
Identifiable assets		$ 5,211,165	$ 4,355,252
Total
Revenue from operations		31,512,276	61,392,349
Less: cost of operations	[1]	(34,769,756)	(52,721,430)
Other non-interest income	[2]	130,665	62,500
Adjusted EBITDA		(3,126,815)	8,733,419
Less: JMA Profit Share	[3]	671,092	(2,438,637)
Depletion, depreciation and amortization		(440,453)	(399,231)
Interest expense, net		(418,809)	(204,569)
Income (loss) before income taxes		(3,314,985)	5,690,982
Income tax benefit (expense)		1,165,901	(1,989,618)
Net income (loss)		(2,149,084)	3,701,364
Capital expenditures		3,639,645	1,291,915
Identifiable assets		$ 95,208,209	$ 60,640,090

[1] Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.

[2] Other non-interest income reflects FLNG easement revenue. See "Note (19) Commitments and Contingenciesb - FLNG Master Easement Agreement" of this Quarterly Report for further discussion related to FLNG.

[3] The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See "Note (19) Commitments and Contingencies - Genesis Agreements" of this Quarterly Report for further discussion related to the Joint Marketing Agreement.

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5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Unrealized hedging gains	$ 1,190,640
Prepaid insurance	155,782	$ 315,120
Prepaid listing fees	$ 11,250
Prepaid related party operating expenses		$ 624,570
Prepaid Expenses, Net	$ 1,357,672	$ 939,690

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6. Inventory (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
HOBM	$ 8,327,943	$ 5,007,576
Jet fuel	5,547,597	2,045,784
Naphtha	427,496	309,850
AGO	408,152	278,278
Chemicals	101,063	122,777
Crude oil and condensate	19,041	19,041
Propane	11,212	17,860
LPG mix	8,463	7,152
Inventories, Net	$ 14,850,967	$ 7,808,318

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7. Property, Plant and Equipment, Net (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 43,046,528	$ 40,195,928
Pipelines and facilities	2,127,207	2,127,207
Onshore separation and handling facilities	325,435	325,435
Land	602,938	602,938
Other property and equipment	652,795	644,795
Property, Plant and Equipment, Gross	46,754,903	43,896,303
Less: Accumulated depletion, depreciation and amortization	(6,674,613)	(6,234,161)
Property, Plant and Equipment less depreciation	40,080,290	37,662,142
Construction in progress	13,066,919	11,179,670
Property, Plant and Equipment, Net	$ 53,147,209	$ 48,841,812

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8. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 954,134	$ 556,032

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8. Accounts Payable, Related Party (Details Narrative) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Accounts payable, related party	$ 408,556		$ 300,000
Expense for service	$ 275,000	$ 0
Prepaid related party operating expenses			624,570
Ingleside [Member]
Accounts payable, related party	$ 172,389		300,000
LEH [Member]
Accounts payable, related party	77,836
Expense for service	3,162,017		2,880,971
Prepaid related party operating expenses	624,570
Jonathan Carroll [Member]
Accounts payable, related party	$ 158,331		$ 0

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9. Long-Term Debt, Net (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Principal balance outstanding	$ 36,694,236	$ 37,172,668
Debt Issue Costs	(2,359,359)	(2,391,482)
Long-Term Debt, Net	34,334,877	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion	(32,942,090)	32,846,254
Long term debt	1,392,787	1,482,801
First Term Loan Due 2034 [Member]
Principal balance outstanding	24,464,586	24,643,081
Debt Issue Costs	(1,601,787)	(1,623,810)
Long-Term Debt, Net	22,862,799	23,019,271
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,926,704	10,000,000
Debt Issue Costs	(757,572)	(767,672)
Long-Term Debt, Net	9,169,132	9,232,328
Long term debt	10,000,000
Notre Dame Debt [Member]
Principal balance outstanding	$ 1,300,000	$ 1,300,000
Debt Issue Costs
Long-Term Debt, Net	$ 1,300,000	$ 1,300,000
Long term debt	8,000,000
Term Loan Due 2017 [Member]
Principal balance outstanding	$ 739,974	$ 924,969
Debt Issue Costs
Long-Term Debt, Net	$ 739,974	$ 924,969
Long term debt	2,000,000
Capital Leases [Member]
Principal balance outstanding	$ 262,972	$ 304,618
Debt Issue Costs
Long-Term Debt, Net	$ 262,972	$ 304,618

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9. Long-Term Debt, Net (Details 1) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notre Dame Debt	$ 1,534,661	$ 1,482,801
First Term Loan Due 2034	45,894	34,883
Second Term Loan Due 2034	34,630	39,193
Term Loan Due 2017	4,779	4,779
Capital leases	2,255	2,612
Total	1,622,219	1,564,268
Less: Interest payable, current portion	(87,558)	(81,467)
Long term debt	$ 1,534,661	$ 1,482,801

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9. Long-Term Debt, Net (Details 2) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Boiler equipment	$ 538,598	$ 538,598
Less: accumulated depreciation
Capital lease obligation	$ 538,598	$ 538,598

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9. Long-Term Debt, Net (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Principal balance outstanding	$ 1,392,787	$ 1,482,801
Term Loan Due 2017 [Member]
Principal balance outstanding	2,000,000
Guaranty fees	4,008	0
Notre Dame Debt [Member]
Principal balance outstanding	8,000,000
Second Term Loan Due 2034 [Member]
Interest accrued	74,111
Principal balance outstanding	10,000,000
Guaranty fees	49,747	0
First Term Loan Due 2034 [Member]
Guaranty fees	$ 122,633
First Term Loan Due 2034 [Member]
Guaranty fees		$ 0

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10. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Disclosure Text Block Supplement [Abstract]
Excise and income taxes payable	$ 1,080,083	$ 1,290,101
Unearned revenue	315,000	781,859
Other payable	131,115	157,714
Board of director fees payable	98,929	86,429
Insurance	64,390	$ 103,024
Property taxes	$ 29,678
Genesis JMA Profit Share payable		$ 388,364
Unrealized hedging loss		183,400
Accrued Expenses and Other Current Liabilities, Net	$ 1,719,195	$ 2,990,891

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11. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, at the beginning of the period	$ 1,985,864	$ 1,866,770	$ 1,866,770
New asset retirement obligations and adjustments			49
Liabilities settled	$ (36,043)		(92,330)
Accretion expense	28,186	$ 53,215	211,375
Asset retirement obligations	1,978,007		1,985,864
Less: asset retirement obligations, current portion	(38,644)		(38,644)
Long-term asset retirement obligations, at the end of the period	$ 1,939,363		$ 1,947,220

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11. Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Liabilities settled recognized	$ 36,043		$ 92,330
Abandonment expense	$ 0	$ 0

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12. Treasury Stock (Details Narrative) - shares	Mar. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Treasury stock	150,000	150,000

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13. Concentration of Risk (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Total refined petroleum product sales	$ 31,193,137	$ 61,067,062
Concentration Risk	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 250,547	$ 57,308
Concentration Risk	0.80%	0.00%
Naphtha
Total refined petroleum product sales	$ 9,025,521	$ 13,416,199
Concentration Risk	28.90%	22.00%
Jet Fuel
Total refined petroleum product sales	$ 8,506,313	$ 16,519,503
Concentration Risk	27.30%	27.10%
HOBM
Total refined petroleum product sales	$ 3,163,495	$ 17,409,079
Concentration Risk	10.10%	28.50%
Reduced crude
Total refined petroleum product sales	$ 3,245,807
Concentration Risk	10.40%	0.00%
AGO
Total refined petroleum product sales	$ 7,001,454	$ 13,664,973
Concentration Risk	22.50%	22.40%

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13. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Concentration Risk	100.00%	100.00%
FDIC insurance limit	$ 250,000		$ 250,000
Excess of the FDIC insurance limit	$ 15,507,858		$ 19,594,883
Sales Revenue [Member] | Five customers [Member]
Concentration Risk	75.40%
Sales Revenue [Member] | Three customers [Member]
Concentration Risk		67.00%
Account receivable [Member] | Five customers [Member]
Concentration risk accounts receivable	$ 2,300,000	$ 4,100,000

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14. Leases (Details Narrative) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Leases, Operating [Abstract]
Rent expense	$ 29,857	$ 25,829

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15. Income Taxes (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Current:
Federal		$ (99,281)
State		(82,853)
Deferred:
Federal	$ 1,165,901	(1,807,484)
Income tax benefit (expense)	$ 1,165,901	$ (1,989,618)

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15. Income Taxes (Details 2) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Balance	$ 19,231,390	$ 22,912,701
Net operating losses	5,871,350
Net operating loss carryforwards utilized		(3,681,311)
Balance	25,102,740	19,231,390
Pre-Ownership Change [Member]
Balance	$ 9,614,449	10,766,912
Net operating losses
Net operating loss carryforwards utilized		(1,152,463)
Balance	$ 9,614,449	9,614,449
Post-Ownership Change [Member]
Balance	9,616,941	12,145,789
Net operating losses	5,871,350
Net operating loss carryforwards utilized		(2,528,848)
Balance	$ 15,488,291	$ 9,616,941

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15. Income Taxes (Details 3) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 10,805,253	$ 8,815,794
Start-up costs (Nixon Facility)	1,476,365	1,510,699
Asset retirement obligations liability/deferred revenue	$ 711,507	717,723
Unrealized hedges		62,356
AMT credit and other	$ 219,814	302,086
Total deferred tax assets	13,212,939	11,408,658
Deferred tax liabilities:
Fair market value adjustments	(46,116)	$ (46,116)
Unrealized hedges	(404,818)
Basis differences in property and equipment	(5,718,545)	$ (5,484,983)
Total deferred tax liabilities	(6,169,479)	(5,531,099)
Deferred tax assets, net	7,043,460	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 4,773,138	$ 3,607,237

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15. Income Taxes (Details 4) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current deferred tax assets	$ 4,845,465	$ 3,486,746
Noncurrent deferred tax assets, net	2,197,995	2,390,813
Deferred tax assets, net	7,043,460	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 4,773,138	$ 3,607,237

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15. Income Taxes (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets	$ 4,800,000	$ 3,600,000

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16. Earnings per share (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (2,149,084)	$ 3,701,364
Basic and diluted income per share	$ (0.21)	$ 0.35
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,457,794	10,449,444

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17. Fair Value Measurement (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Financial assets (liabilties):
Commodity contracts	$ 1,190,640	$ (183,400)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Financial assets (liabilties):
Commodity contracts	$ 1,190,640	$ (183,400)
Significant Other Observable Inputs (Level 2) [Member]
Financial assets (liabilties):
Commodity contracts
Significant Unobservable Inputs (Level 3) [Member]
Financial assets (liabilties):
Commodity contracts

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17. Fair Value Measurement (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of long term debt and short-term notes payable	$ 34,334,877	$ 34,781,186

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18. Inventory Risk Management (Details) - Refined products - net short (long) positions	Mar. 31, 2016 shares
Volume in Thousands of barrels
Notional Contract Volumes 2016	460,000
Notional Contract Volumes 2017
Notional Contract Volumes 2018

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18. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 1,190,640		$ (183,400)
Cost of refined products sold	$ (492,528)	$ 927,584

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19. Commitments and Contingencies (Details Narrative) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Credit and cash backed rights of way bonds issued to the BOEM	$ 900,000	$ 900,000