10-Q

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended:  September 30, 2016

☐ 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 ☒ No ☐

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 ☒ No ☐

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	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒
(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 ☐ No ☒

Number of shares of common stock, par value $0.01 per share outstanding as of November 14, 2016:  10,474,714

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

TABLE OF CONTENTS

GLOSSARY OF SELECTED OIL AND GAS TERMS		3
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	37
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 4.	CONTROLS AND PROCEDURES	59
PART II	OTHER INFORMATION	60
ITEM 1.	LEGAL PROCEEDINGS	60
ITEM 1A.	RISK FACTORS	60
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	61
ITEM 4.	MINE SAFETY DISCLOSURES	61
ITEM 5.	OTHER INFORMATION	61
ITEM 6.	EXHIBITS	61
SIGNATURES		63

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

GLOSSARY OF SELECTED OIL AND GAS TERMS

The following are abbreviations and definitions of certain commonly used oil and gas industry terms that are used in this Form 10-Q for the quarterly period ended September 30, 2016 (this “Quarterly Report”):

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 the bbls of daily output produced in a refinery or transported through a pipeline.

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 9/30/16

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 also 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 9/30/16

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

	September 30,	December 31,
	2016	2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$1,677,485	$1,853,875
Restricted cash	4,160,999	3,175,299
Accounts receivable, net	7,412,697	5,457,245
Prepaid expenses and other current assets	196,101	939,690
Deposits	136,970	395,414
Inventory	8,819,980	7,808,318
Total current assets	22,404,232	19,629,841
Total property and equipment, net	61,283,727	48,841,812
Restricted cash, noncurrent	4,358,581	15,616,478
Surety bonds	710,000	1,022,000
Trade name	303,346	303,346
Deferred tax assets, net	7,342,277	3,607,237
Total long-term assets	73,997,931	69,390,873
TOTAL ASSETS	$96,402,163	$89,020,714
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$23,886,185	$14,882,714
Accounts payable, related party	-	300,000
Asset retirement obligations, current portion	25,972	38,644
Accrued expenses and other current liabilities	3,063,080	2,990,891
Interest payable, current portion	158,706	81,467
Long-term debt less unamortized debt issue costs, current portion	32,120,782	1,934,932
Long-term debt, related party, current portion	500,000	-
Total current liabilities	59,754,725	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,983,042	1,947,220
Deferred revenues and expenses	93,814	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,342,363	32,846,254
Long-term debt, related party, net of current portion	6,398,931	-
Long-term interest payable, net of current portion	1,638,952	1,482,801
Total long-term liabilities	11,457,102	36,401,360
TOTAL LIABILITIES	71,211,827	56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,614,715 and
10,603,802 shares issued at September 30, 2016 and December 31, 2015, respectively)	106,148	106,038
Additional paid-in capital	36,788,628	36,738,737
Accumulated deficit	(10,904,440)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	25,190,336	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$96,402,163	$89,020,714

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$53,951,293	$54,924,070	$126,546,716	$174,830,292
Tank rental revenue	717,487	286,892	1,624,461	860,676
Pipeline operations	19,526	45,925	71,865	119,882
Total revenue from operations	54,688,306	55,256,887	128,243,042	175,810,850
COST OF OPERATIONS
Cost of refined products sold	51,689,474	48,415,627	125,316,249	151,604,774
Refinery operating expenses	3,153,646	2,953,528	9,468,409	8,420,650
Joint Marketing Agreement profit share	965,627	1,435,376	392,062	4,812,674
Pipeline operating expenses	91,969	63,099	266,454	170,582
Lease operating expenses	9,005	(1,143)	32,112	20,271
General and administrative expenses	891,210	312,365	1,503,533	1,058,267
Depletion, depreciation and amortization	504,719	414,837	1,415,519	1,217,005
Recovery of bad debt	-	-	(139,868)	-
Accretion expense	28,186	52,720	84,558	158,655
Total cost of operations	57,333,836	53,646,409	138,339,028	167,462,878
Income (loss) from operations	(2,645,530)	1,610,478	(10,095,986)	8,347,972
OTHER INCOME (EXPENSE)
Easement, interest and other income	157,840	724,349	415,700	856,816
Interest and other expense	(485,659)	(382,191)	(1,305,125)	(1,322,562)
Total other income (expense)	(327,819)	342,158	(889,425)	(465,746)
Income (loss) before income taxes	(2,973,349)	1,952,636	(10,985,411)	7,882,226
Income tax benefit (expense)	1,034,798	(688,403)	3,735,040	(2,778,750)
Net income (loss)	$(1,938,551)	$1,264,233	$(7,250,371)	$5,103,476
Income (loss) per common share:
Basic	$(0.19)	$0.12	$(0.69)	$0.49
Diluted	$(0.19)	$0.12	$(0.69)	$0.49
Weighted average number of common shares outstanding:
Basic	10,464,715	10,453,802	10,460,849	10,451,168
Diluted	10,464,715	10,453,802	10,460,849	10,451,168

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2016	2015
OPERATING ACTIVITIES
Net income (loss)	$(7,250,371)	$5,103,476
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization	1,415,519	1,217,005
Unrealized loss (gain) on derivatives	1,143,490	362,750
Deferred tax expense (benefit)	(3,735,040)	2,479,823
Amortization of debt issue costs	96,364	517,652
Accretion expense	84,558	158,655
Common stock issued for services	50,000	19,999
Recovery of bad debt	(139,868)	-
Changes in operating assets and liabilities
Accounts receivable	(1,815,584)	506,784
Prepaid expenses and other current assets	945,539	(274,435)
Deposits and other assets	570,444	(1,711,073)
Inventory	(1,011,662)	(2,420,176)
Accounts payable, accrued expenses and other liabilities	5,269,224	1,172,976
Accounts payable, related party	(300,000)	(1,174,168)
Net cash provided by (used in) operating activities	(4,677,387)	5,959,268
INVESTING ACTIVITIES
Capital expenditures	(11,255,725)	(8,156,298)
Change in restricted cash for investing activities	11,257,897	(13,021,438)
Net cash provided by (used in) investing activities	2,172	(21,177,736)
FINANCING ACTIVITIES
Proceeds from issuance of debt	6,898,931	28,000,000
Payments on long-term debt	(1,414,406)	(9,474,720)
Change in restricted cash for financing activities	(985,700)	(3,081,686)
Net cash provided by financing activities	4,498,825	15,443,594
Net increase (decrease) in cash and cash equivalents	(176,390)	225,126
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$1,677,485	$1,518,359
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	$2,601,709	$1,743,997
Interest paid	$1,827,794	$959,665
Income taxes paid	$-	$139,500

See accompanying notes to consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements
(1)	Organization

Nature of Operations. Blue Dolphin Energy Company (“Blue Dolphin,”) 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. (See “Note (4) Business Segment Information” for further discussion of our business segments.)

Structure and Management.Blue Dolphin was 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) Related Party Transactions,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Operating Agreement, and Jonathan Carroll.)

Our operations are conducted through the following active 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 (“BDPL”), a Delaware corporation.

●

Blue Dolphin Petroleum Company, a Delaware corporation.

●

Blue Dolphin Services Co., a Texas corporation.

See "Part I, Item 1. Business and Item 2. Properties” in our Form 10-K 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, principal facilities, and assets.

References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires.

Operating Risks. Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit 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 business and operational strategy will achieve anticipated outcomes.  Our operations, liquidity, and financial condition may be materially adversely affected if: (i) our strategy is not successful, (ii) our working capital requirements are not funded through Operations Payments by GEL TEX Marketing, LLC (“GEL”) under a Joint Marketing Agreement (the “Joint Marketing Agreement”), our profit share under the Joint Marketing Agreement, or certain advances from LEH, or (iii) we have future covenant violations under our loan agreements that are not waived.

For the three months ended September 30, 2016, we had a net loss of $1,938,551 compared to net income of $1,264,233 for the three months ended September 30, 2015. For the nine months ended September 30, 2016, we had a net loss of $7,250,371 compared to net income of $5,103,476 for the nine months ended September 30, 2015.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

As of September 30, 2016, we had cash and cash equivalents and restricted cash (current portion) of $1,677,485 and $4,160,999, respectively. As of September 30, 2016, we had current assets of $22,404,232 and current liabilities (including the current portion of long-term debt) of $59,754,725, reflecting a working capital deficit of $37,350,493. Excluding the current portion of long-term debt, we had a working capital deficit of $5,229,711 as of September 30, 2016. Non-payment of Operations Payments to us by GEL under the Joint Marketing Agreement resulting from a contract-related dispute between the parties contributed to the working capital deficit as of September 30, 2016. (See “Note (19) Commitments and Contingencies – Genesis Agreements and Legal Matters” for a discussion related to Operations Payments and the Joint Marketing Agreement.)

As of December 31, 2015, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively. As of December 31, 2015, we had current assets of $19,629,841 and current liabilities (including the current portion of long-term debt) of $20,228,648, reflecting a working capital deficit of $598,807.

In addition to the Joint Marketing Agreement, 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.   An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contract-related dispute with Genesis.)

As of September 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank (“Sovereign”). As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.  Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (9) Long-Term Debt, Net” and “Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

(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.

The consolidated balance sheet as of 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 and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the fiscal 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 their integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 $1,677,485 and $1,853,875 as of September 30, 2016 and December 31, 2015, respectively.

Restricted Cash.As of September 30, 2016, total restricted cash was $8,519,580, comprised of restricted cash (current portion) totaling $4,160,999 and restricted cash, noncurrent totaling $4,358,581. As of December 31, 2015, total restricted cash was $18,791,777, comprised of restricted cash (current portion) totaling $3,175,299 and restricted cash, noncurrent totaling $15,616,478.Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See “Note (9) Long-Term Debt, Net” for additional disclosures related to our 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 as of September 30, 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. 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” 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, commodity futures contracts may be used 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 hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements 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” for additional disclosures related to derivatives.)

10

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 for any period presented.

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 and nine months ended September 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of 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” 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 Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of September 30, 2016 and December 31, 2015. We have determined the 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. Jet fuel, our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and 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.

11

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 abandoning a segment of the pipeline assets. (See “Part I, Business – Governmental Regulation – Offshore Safety and Environmental Oversight – Decommissioning Requirements” in 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 three and nine month periods 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 a 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” 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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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” 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 directors, including the issuance of restricted common stock, 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” for additional disclosures related to treasury stock.)

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. For the three and nine months ended September 30, 2016, we adopted the following recently issued ASU’s:

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.

ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has 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. The following are recently issued, but not yet effective, ASU’s that may have an effect on our consolidated financial position, results of operations, or cash flows:

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15. This guidance addresses eight specific cash flow issues in order to reduce future diversity of practice. For public business entities, the amendments in ASU 2016-15 are effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated statements of cash flows.

ASU 2016-13,Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13.This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.

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 2015-11, 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 and the International Accounting Standards Board (the “IASB”) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the “Accounting Boards”) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the “TRG”). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASU’s as part of the TRG process include:

●

August 2015 – 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).

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

 

●

March 2016 – 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.

●

April 2016 – ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU: (i) clarifies when promised goods or services are separately identifiable (i.e., distinct within the context of a contract), an important step in determining whether goods and services should be accounted for as separate performance obligations, (ii) allows entities to disregard goods or services that are immaterial in the context of a contract and provide an accounting policy election for accounting for certain shipping and handling activities, (iii) clarifies how an entity should evaluate the nature of its promise in granting a license of intellectual property, which will determine whether the entity recognizes revenue over time or at a point in time, and (iv) revises the guidance to address how entities should apply the exception for sales and usage-based royalties to licenses of intellectual property, recognize revenue for licenses that are not separate performance obligations, and evaluate different types of license restrictions (e.g., time-based, geography-based).

●

May 2016 – ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update). Upon the adoption of ASU 2014-16, Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, and ASU 2014-09, several ASC guidance standards related to revenue recognition will be rescinded as no longer needed. These include ASC guidance standards for determining the nature of a host contract related to a hybrid financial instrument issued in the form of a share, revenue and expense recognition for freight services in process, accounting for shipping and handling fees and costs, accounting for consideration given by a vendor to a customer, and accounting for gas-balancing arrangements.

●

May 2016 – ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients addresses issues such as collectability, contract modifications, completed contracts at transition, and noncash considerations as they relate to the new revenue recognition standard. 

We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and ASU 2016-12, 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 September 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.

Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation.

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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 periods indicated (and as of the dates indicated), was as follows:

	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$54,668,780	$19,526	$-	$54,688,306	$55,210,962	$45,925	$-	$55,256,887
Less: cost of operations(1)	(55,495,575)	(129,160)	(238,755)	(55,863,490)	(51,444,705)	(114,675)	(236,816)	(51,796,196)
Other non-interest income(2)	-	156,396	-	156,396	-	62,500	660,000	722,500
Adjusted EBITDA(3)	(826,795)	46,762	(238,755)	(1,018,788)	3,766,257	(6,250)	423,184	4,183,191
Less: JMA Profit Share(4)	(965,627)	-	-	(965,627)	(1,435,376)	-	-	(1,435,376)
EBITDA(3)	$(1,792,422)	$46,762	$(238,755)		$2,330,881	$(6,250)	$423,184
Depletion, depreciation and amortization				(504,719)				(414,837)
Interest expense, net				(484,215)				(380,342)
Income (loss) before income taxes				(2,973,349)				1,952,636
Income tax benefit (expense)				1,034,798				(688,403)
Net income (loss)				$(1,938,551)				$1,264,233
Capital expenditures(5)	$4,182,747	$-	$-	$4,182,747	$2,355,811	$-	$-	$2,355,811
Identifiable assets(6)	$85,585,499	$3,106,327	$7,710,337	$96,402,163	$78,145,626	$3,303,803	$3,405,977	$84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$128,171,177	$71,865	$-	$128,243,042	$175,690,968	$119,882	$-	$175,810,850
Less: cost of operations(1)	(135,452,537)	(383,124)	(695,786)	(136,531,447)	(160,208,576)	(296,291)	(928,331)	(161,433,198)
Other non-interest income(2)	-	412,061	-	412,061	-	187,500	660,000	847,500
Adjusted EBITDA(3)	(7,281,360)	100,802	(695,786)	(7,876,344)	15,482,392	11,091	(268,331)	15,225,152
Less: JMA Profit Share(4)	(392,062)	-	-	(392,062)	(4,812,674)	-	-	(4,812,674)
EBITDA(3)	$(7,673,422)	$100,802	$(695,786)		$10,669,718	$11,091	$(268,331)
Depletion, depreciation and
amortization				(1,415,519)				(1,217,005)
Interest expense, net				(1,301,486)				(1,313,247)
Income (loss) before income taxes				(10,985,411)				7,882,226
Income tax benefit (expense)				3,735,040				(2,778,750)
Net income (loss)				$(7,250,371)				$5,103,476
Capital expenditures(5)	$11,255,725	$-	$-	$11,255,725	$8,156,298	$-	$-	$8,156,298
Identifiable assets(6)	$85,585,499	$3,106,327	$7,710,337	$96,402,163	$78,145,626	$3,303,803	$3,405,977	$84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.
(5)	Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets as of the dates indicated consisted of the following:

	September 30,	December 31,
	2016	2015
Prepaid insurance	$192,351	$315,120
Prepaid listing fees	3,750	-
Prepaid related party operating expenses	-	624,570
	$196,101	$939,690

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

(6) Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,	December 31,
	2016	2015
HOBM	$4,069,203	$5,007,576
Jet fuel	3,744,702	2,045,784
Naphtha	417,223	309,850
AGO	280,277	278,278
Chemicals	261,518	122,777
Propane	24,860	17,860
Crude oil and condensate	19,041	19,041
LPM mix	3,156	7,152
	$8,819,980	$7,808,318

(7) Property, Plant and Equipment, Net

Property, plant and equipment, net, as of the dates indicated consisted of the following:

	September 30,	December 31,
	2016	2015
Refinery and facilities	$50,516,486	$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
	54,224,861	43,896,303
Less: Accumulated depletion, depreciation, and amortization	(7,649,077)	(6,234,161)
	46,575,784	37,662,142
Construction in progress	14,707,943	11,179,670
	$61,283,727	$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 depreciated over the asset’s useful life. Interest cost capitalized was $1,776,863 and $556,032 as of September 30, 2016 and December 31, 2015, respectively.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

(8) Related Party Transactions

We are party to several agreements with related parties. We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. A summary of these agreements follows:

LEH. We are party to an Operating Agreement, a Product Sales Agreement, a Terminal Services Agreement, a Loan and Security Agreement, and a Promissory Note with LEH. 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.

Operating Agreement. LEH manages and operates all of our properties pursuant to the Operating Agreement. 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 under the Operating Agreement, 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 either reflected within prepaid expenses and other current assets or accounts payable, related party in our consolidated balance sheets. (See “Note (5) Prepaid Expenses and Other Current Assets” for additional disclosures with respect to prepaid related party operating expenses.)

●

Fees – For management and operation of the Nixon Facility, LEH receives: (i) weekly payments from GEL to cover direct expenses incurred in an amount not to exceed $750,000 per month (the “Operations Payments”), (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 to LEH are reflected within refinery operating expenses in our consolidated statements of operations. Fees owed to LEH under the Operating Agreement are reflected within accounts payable, related party in our consolidated balance sheets.

Product Sales Agreement. Under a Product Sales Agreement, LEH purchases jet fuel from the Nixon Facility for resale to third parties. Sales to LEH under the Product Sales Agreement are reflected within refined petroleum product sales in our consolidated statements of operations.

Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leases a petroleum storage tank at the Nixon Facility. The Terminal Services Agreement has an initial term of 12 months and automatically renews for additional terms of 6 months. The parties may terminate the Terminal Services Agreement upon 45 days’ written notice. Rental fees received from LEH under the Terminal Services Agreement are reflected within tank rental revenue in our consolidated statements of operations.

Loan and Security Agreement. In August 2016, BDPL entered into a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “LEH Loan Agreement”). The LEH Loan Agreement matures in August 2018, and accrues interest at rate of 16.00%. Under the LEH Loan Agreement, BDPL will make payments of $500,000 per year from the annual payment received from FLNG pursuant to a Master Easement Agreement between BDPL and FLNG dated December 11, 2013. A final balloon payment is due at maturity.

The proceeds of the LEH Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the LEH Loan Agreement. The LEH Loan Agreement is secured by: (i) the assignment of payments received by BDPL from FLNG under the Master Easement Agreement and (ii) certain real estate assets of BDPL. Outstanding principal and interest less associated debt issue costs owed to LEH under the LEH Loan Agreement are reflected in long-term debt, related party, current portion and long-term debt, related party, net of current portion in our consolidated balance sheets.

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with LEH in the original principal amount of $1,797,172 (the “LEH Note”). The LEH Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to LEH under the LEH Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

19

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

Ingleside Crude, LLC (“Ingleside”). We are party to an Amended and Restated Tank Lease Agreement and a Promissory Note with Ingleside. Ingleside is a related party of LEH and Jonathan Carroll.

Amended and Restated Tank Lease Agreement. Pursuant to an Amended and Restated Tank Lease Agreement with Ingleside, we lease petroleum storage tanks to meet periodic, additional storage needs. The Amended and Restated Tank Lease Agreement had an initial term of 30 days with automatic 30-day renewal periods. The parties may terminate the tank lease agreement upon 30 days’ written notice. Renatal fees owed to Ingleside under the tank lease agreement are reflected within accounts payable, related party in our consolidated balance sheets. Amounts expensed as rental fees to Ingleside under the Amended and Restated Tank Lease Agreement are reflected within refinery operating expenses in our consolidated statements of operations.

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with Ingleside in the original principal amount of $679,385 (the “Ingleside Note”). The Ingleside Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to Ingleside under the Ingleside Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

Jonathan Carroll. We are party to Guaranty Fee Agreements and a Promissory Note with Jonathan Carroll. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin.

Guaranty Fee Agreements. Pursuant to Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt. Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain loan agreements. Amounts owed to Jonathan Carroll under Guaranty Fee Agreements are reflected within accounts payable, related party in our consolidated balance sheets. (See “Note (9) Long-Term Debt, Net” for further discussion related to the Guaranty Fee Agreements.)

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with Jonathan Carroll in the original principal amount of $422,374 (the “Carroll Note”). The Carroll Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Carroll Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to Jonathan Carroll under the Carroll Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

As of September 30, 2016, accounts receivable related to LEH totaled $2,869,805.

 

Unsettled reimbursements associated with the Operating Agreement and reflected within prepaid expenses and other current assets as of the dates indicated were as follows:

	September 30,	December 31,
	2016	2015
LEH	$-	$624,570
	$-	$624,570

20

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
LEH	$5,797,172	$-
Ingleside	679,385
Jonathan Carroll	422,374
	6,898,931	-
Less: Long-term debt,
related party,
current portion	(500,000)	-
	$6,398,931	$-

Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
LEH	$80,000	$-
	80,000	-
Less: Interest payable,
current portion	(80,000)	-
	$-	$-

Accounts payable, related party associated with the Amended and Restated Tank Lease Agreement as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
Ingleside	$-	$300,000
	$-	$300,000

21

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

Refinery operating expenses associated with the Operating Agreement Amended and Restated Tank Lease Agreement for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	Amount	Per bbl	Amount	Per bbl	Amount	Per bbl	Amount	Per bbl
LEH	$3,028,646	$2.66	$2,953,528	$2.66	$8,618,409	$2.84	$8,420,650	$2.73
Ingleside	125,000	$0.11	-	$0.00	850,000	$0.28	-	$0.00
	$3,153,646	$2.77	$2,953,528	$2.66	$9,468,409	$3.12	$8,420,650	$2.73

Revenue associated with the Product Sales Agreement and Terminal Services Agreement for the periods indicated was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Refined petroleum product sales
LEH	$14,536,997	$-	$23,449,071	$-
Other customers	39,414,296	54,924,070	103,097,645	174,830,292
Total refined petroleum product sales	53,951,293	54,924,070	126,546,716	174,830,292
Tank rental revenue
LEH	426,000	-	750,000	-
Other customers	291,487	286,892	874,461	860,676
Total tank rental revenue	717,487	286,892	1,624,461	860,676
Pipeline operations
Other customers	19,526	45,925	71,865	119,882
Total revenue from operations	$54,688,306	$55,256,887	$128,243,042	$175,810,850

Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated were as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Jonathan Carroll	$172,300	$165,008	$522,931	$165,008
LEH	80,000	-	80,000	-
	$252,300	$165,008	$602,931	$165,008

22

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

(9) Long-Term Debt, Net

Effective January 1, 2016, we adopted the provisions of the FASB ASC guidance that requires debt issue costs to be presented as an offset to their related debt. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported debt issue costs as a direct deduction of long-term debt.

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

	September 30, 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	$24,111,986	$(1,557,748)	$22,554,238	$24,643,081	$(1,623,810)	$23,019,271
Second Term Loan Due 2034	9,797,549	(737,370)	9,060,179	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	369,987	-	369,987	924,969	-	924,969
Capital Leases	178,741	-	178,741	304,618	-	304,618
	$35,758,263	$(2,295,118)	$33,463,145	$37,172,668	$(2,391,482)	$34,781,186
Less: Long-term debt less
unamortized debt issue
costs, current portion			(32,120,782)			(1,934,932)
			$1,342,363			$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) as of the dates indicated consisted of the following:

	September 30,	December 31,
	2016	2015
Notre Dame Debt	$1,638,952	$1,482,801
LEH Loan Agreement	80,000	-
Second Term Loan Due 2034	43,836	39,193
First Term Loan Due 2034	33,030	34,883
Capital Leases	1,531	2,612
Term Loan Due 2017	309	4,779
	1,797,658	1,564,268
Less: Interest payable, current portion	(158,706)	(81,467)
	$1,638,952	$1,482,801

(See “Note (8) Related Party Transactions” for disclosures related to related party long-term debt.)

23

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

First Term Loan Due 2034. In June 2015, LE entered into a loan agreement and related security agreementwith Sovereign as administrative agent and lender, providing for 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 a current monthly payment of principal and interest of $188,416, 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 (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As of September 30, 2016, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the First Term Loan Due 2034. As a result of these covenant defaults, Sovereign could declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with the loan was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the First Term Loan Due 2034 and financial covenant violations.)

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 September 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $121,048 and $142,002, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $365,420 and $142,002, 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) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. 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. In December 2015, LRM entered into a loan agreement and related security agreement with Sovereign as administrative agent and lender, providing for 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 a current monthly payment 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 (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As of September 30, 2016, LRM was in violation of the debt service coverage ratio, the current ratio, and the debt to net worth ratio financial covenants related to the Second Term Loan Due 2034. As a result of these covenant defaults, Sovereign could declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available.  Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with the loan was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.)

24

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 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 September 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,094 and $0, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $148,261 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) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from 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 certain specified tanks, with respect to which Sovereign has 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.

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 Term Loan Due 2017 has a current monthly principal payment of $61,665 plus interest. Due to its maturity date, the Term Loan Due 2017 was classified within the current portion of long-term debt on our consolidated balance sheet as of September 30, 2016.

As of September 30, 2016, LRM was in violation of the debt service coverage ratio financial covenant related to the Term Loan Due 2017. As a result of this covenant default, Sovereign could declare the amounts owed under the Term Loan Due 2017 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. The Term Loan Due 2017 was already classified within the current portion of long-term debt on our consolidated balance sheets due to the loan’s short-term maturity date. Sovereign waived the financial covenant default as of the quarter ended September 30, 2016. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.)

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 September 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $2,158 and $6,506, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $9,250 and $6,506, respectively. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations.

25

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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) Related Party Transactions” 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 as of the dates indicated follows:

	September 30,	December 31,
	2016	2015
Boiler equipment	$538,598	$538,598
Less: accumulated depreciation	-	-
	$538,598	$538,598

(10) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities as of the dates indicated consisted of the following: 

	September 30,	December 31,
	2016	2015
Unrealized hedging loss	$1,326,890	$183,400
Unearned revenue	597,162	781,859
Customer deposits	450,000	-
Genesis JMA Profit Share payable	245,255	388,364
Other payable	166,314	157,714
Board of director fees payable	133,929	86,429
Property taxes	92,678	-
Transportation and inspection	38,000	-
Excise and income taxes payable	12,852	1,290,101
Insurance	-	103,024
	$3,063,080	$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.

26

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 depreciate 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:

	September 30,	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	(61,408)	(92,330)
Accretion expense	84,558	211,375
	2,009,014	1,985,864
Less: asset retirement obligations, current portion	(25,972)	(38,644)
Long-term asset retirement obligations, at the end of the period	$1,983,042	$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. As of September 30, 2016 and December 31, 2015, we recognized $61,408 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 September 30, 2016 and 2015, we recognized $0 in abandonment expense. For the nine months ended September 30, 2016 and 2015, we recognized $0 in abandonment expense.

(12) Treasury Stock

As of September 30, 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. As of September 30, 2016 and December 31, 2015, we had cash balances in excess of the FDIC insurance limit per depositor in the amount of $9,345,560 and $19,594,883, respectively.

Key Supplier. Under a Crude Oil and Supply Throughput Services Agreement dated in August 2011 (the “Crude Supply Agreement”), GEL supplies crude oil and condensate to the Nixon Facility. The initial term of the Crude Supply Agreement 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., another Genesis affiliate (“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.

(See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Crude Supply Agreement and a discussion of the current contract-related dispute with Genesis.)

27

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

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 September 30, 2016, we had 4 customers that accounted for approximately 70% of our refined petroleum products sales. These 4 customers represented approximately $6.7 million in accounts receivable as of September 30, 2016. For the three months ended September 30, 2015, we had 5 customers that accounted for approximately 81% of our refined petroleum products sales. These 5 customers represented approximately $5.7 million in accounts receivable as of September 30, 2015.

For the nine months ended September 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum products sales. These 4 customers represented approximately $5.5 million in accounts receivable as of September 30, 2016. For the nine months ended September 30, 2015, we had 3 customers that accounted for approximately 55% of our refined petroleum products sales. These 3 customers represented approximately $4.4 million in accounts receivable as of September 30, 2015.

For the three months ended September 30, 2016, 1 of our 4 significant customers was LEH, a related party. LEH accounted for approximately 27% of our refined petroleum product sales. For the nine months ended September 30, 2016, LEH accounted for approximately 19% of our refined petroleum product sales. As of September 30, 2016, LEH represented approximately $2.9 million in accounts receivable. LEH was not a customer during 2015. (See “Note (8) Related Party Transactions” for additional disclosures with respect to related parties.)

Refined Petroleum Product Sales. Our refined petroleum products are primarily sold in the U.S. However, with the opening of the Mexican diesel market to private companies, we began exporting low sulfur diesel to Mexico during the second quarter of 2016. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
LPG mix	$237,009	0.4%	$617,715	1.1%	$621,313	0.5%	$909,207	0.5%
Naphtha	11,870,484	22.0%	11,218,381	20.4%	28,183,809	22.3%	38,048,064	21.8%
Jet fuel	15,104,900	28.0%	17,782,534	32.4%	41,150,686	32.5%	51,713,507	29.6%
HOBM	14,206,759	26.4%	9,609,536	17.5%	25,259,753	20.0%	40,640,975	23.2%
Reduced Crude		0.0%	50,407	0.1%	3,791,919	3.0%	50,407	0.0%
AGO	12,532,141	23.2%	15,645,497	28.5%	27,539,236	21.7%	43,468,132	24.9%
	$53,951,293	100.0%	$54,924,070	100.0%	$126,546,716	100.0%	$174,830,292	100.0%

(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 that expires in September 2017. The lease included a free rent period, has escalating rent payment provisions, and requires payment of a portion of operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended September 30, 2016 and 2015, rent expense totaled $33,251 and $29,857, respectively. For the nine months ended September 30, 2016 and 2015, rent expense totaled $92,966 and $112,746, respectively.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

(15) Income Taxes

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Current:
Federal	$-	$(37,620)	$-	$(122,863)
State	-	(36,102)	-	(148,656)
Deferred:
Federal	1,034,798	(614,681)	3,735,040	(2,507,231)
	$1,034,798	$(688,403)	$3,735,040	$(2,778,750)

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 basis, 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 for a period of 20 years in addition to available amounts of NOL carryforwards generated prior to the ownership change.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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 Change	Post-Ownership Change	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
Net operating losses	-	4,230,763	4,230,763
Balance at June 30, 2016	9,614,449	19,719,054	29,333,503
Net operating losses	-	2,487,642	2,487,642
Balance at September 30, 2016	$9,614,449	$22,206,696	$31,821,145

Deferred Tax Assets and Liabilities. As of September 30, 2016 and December 31, 2015, approximately $7.3 million and $3.6 million, respectively, of net deferred tax assets remained available for future use. Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:

	September 30,	December 31,
	2016	2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$13,089,512	$8,815,794
Start-up costs (Nixon Facility)	1,407,697	1,510,699
Asset retirement obligations liability/deferred revenue	714,961	717,723
Unrealized hedges	451,141	62,356
AMT credit and other	257,323	302,086
Total deferred tax assets	15,920,634	11,408,658
Deferred tax liabilities:
Fair market value adjustments	(46,116)	(46,116)
Unrealized hedges	-	-
Basis differences in property and equipment	(6,261,919)	(5,484,983)
Total deferred tax liabilities	(6,308,035)	(5,531,099)
	9,612,599	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets, net	$7,342,277	$3,607,237

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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 September 30, 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 $7.3 million and $3.6 million, respectively, were realizable, and as a result, reflected a valuation allowance of $2.3 million at each date.

Current Versus Long-Term. Effective April 1, 2016, we adopted the provisions of the FASB ASC guidance that simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net.

Uncertain Tax Positions. We 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 and nine months ended September 30, 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 September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Net income (loss)	$(1,938,551)	$1,264,233	$(7,250,371)	$5,103,476
Basic and diluted income per share	$(0.19)	$0.12	$(0.69)	$0.49
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,464,715	10,453,802	10,460,849	10,451,168

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 and nine months ended September 30, 2016 and 2015 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

(17) Fair Value Measurement

The purchase and sale of financial instruments may be executed for the purpose of economically hedging commodity price risks associated with our refined petroleum products and the purchase of crude oil and condensate. When executed these financial instruments are direct contractual obligations of our crude supplier and not us. However, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments. 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 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:

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Notes to Consolidated Financial Statements (Continued)

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 as of September 30, 2016 and December 31, 2015 due to their short-term maturities. The fair value of our long-term debt, net including the current portion as of September 30, 2016 and December 31, 2015 was $39,758,263 and $37,172,668, 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 September 30, 2016 and December 31, 2015 and the basis for the measurement:

		Fair Value Measurement at September 30, 2016 Using
Financial assets (liabilities):	Carrying Value at September 30, 2016	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$(1,326,890)	$(1,326,890)	$-	$-

		Fair Value Measurement at December 31, 215 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$(183,400)	$(183,400)	$-	$-

Carrying amounts of commodity contracts 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, commodity futures contracts may be used 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 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 to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. 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.

As of September 30, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered into as economic hedges. 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	290,000	-	-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of September 30, 2016 and December 31, 2015:

		Fair Value
Asset Derivatives	Balance Sheets Location	September 30, 2016	December 31, 2015
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$(1,326,890)	$(183,400)

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended September 30,		Nine Months Ended September 30,
Derivatives	Statements of Operations Location	2016	2015	2016	2015
Commodity contracts	Cost of refined products sold	$770,838	$2,205,291	$(2,588,734)	$1,762,582

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

(19) Commitments and Contingencies

Operating Agreement. (See “Note (8) Related Party Transactions” for additional disclosures related to the Operating Agreement.)

Genesis Agreements. Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows:

Crude Supply Agreement. Under the Crude Supply Agreement, GEL supplies crude oil and condensate to the Nixon Facility. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with 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 within this section. 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 certain output produced at the Nixon Facility and share the associated Gross Profits (as defined below) from such sales. Payments for the sale of certain output produced at the Nixon Facility are made directly to GEL as collection agent, and associated customers must satisfy GEL’s customer credit approval process. The Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of certain output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement). Key provisions of the Joint Marketing Agreement 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. In addition, we are entitled to receive reimbursement for accounting fees, if incurred, not to exceed $50,000 per month. We assigned our rights to the Operations 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 is entitled to receive 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share, and we are entitled to receive 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for a calendar month is payable to GEL and us in the following manner: (i) GEL is entitled to receive 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we are entitled to receive 80% of the remaining Gross Profits over the Threshold Amount as our Profit Share. The GEL Profit Share plus the Performance Fee are collectively referred to as the “Joint Marketing Agreement Profit Share” or the “JMA Profit Share”.

The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. 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, as lender and lienholder pursuant to the First Term Loan Due 2034. (See “Note (9) Long-Term Debt, Net” for further discussion related to the First Term Loan Due 2034.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

Genesis Contract-Related Dispute. LE currently has a contract-related dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement.  (See “Legal Matters” below for a discussion of the current contract-related dispute with Genesis.)

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 August 2015, we received a letter from the Bureau of Ocean Energy Management (the “BOEM”) requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In July 2016, the BOEM issued Notice to Lessees (“NTL”) No. 2016-N01 (Requiring Additional Security), which changes the way that lessees and rights-of-way holders demonstrate financial strength and reliability to plug and abandon wells, as well as decommission and remove platforms and pipelines at the end of production or service activities. The NTL, which changed an earlier supplemental waiver process to a self-insurance model, became effective in September 2016. Pursuant to the NTL, the BOEM requested that lessees submit any relevant information needed for an overall financial review of the lessees account. The BOEM indicated that it would use this information to evaluate a lessees’ ability to carry out its obligations and determine whether, and/or how much self-insurance a lessee can use.

In October 2016, we received a letter from the BOEM summarizing the amount required as additional security on our existing pipeline rights-of-way. The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental pipeline bonds or acceptable financial reassurance of approximately $4.6 million. As of September 30, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. Of the 5 rights-of-ways reflected in the BOEM’s October 2016 letter, one right-of-way was abandoned-in-place in May 1997. We requested permits from the Bureau of Safety and Environmental Enforcement (the “BSEE”) to decommission and abandon-in-place 3 of the rights-of-way in April 2016, one of which also requires approval from the U.S. Army Corps of Engineers. 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. If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

Financing Agreements. (See “Note (9) Long-Term Debt, Net” 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.

Genesis Contract-Related Dispute. As described above under “Genesis Agreements,” we are party to a variety of contracts and agreements with Genesis and its affiliates, including GEL that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services.

In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the “Petition”) against LE and LEH. The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, in connection with an agreement by LEH to supply jet fuel acquired from LE to a customer. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GEL’s claims in the Petition are without merit and intends to defend the matter vigorously.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Notes to Consolidated Financial Statements (Continued)

In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of a Dispute Resolution Agreement between the parties (the “Arbitration”). The Arbitration alleges that GEL breached the Crude Supply Agreement related to:

(i)

failure to provide crude oil and condensate at cost as defined in the Crude Supply Agreement, and

(ii)

significant under delivery of crude oil and condensate, resulting in significant refinery downtime and a significant decrease in refinery throughput, refinery production, and refined petroleum product sales for the nine months ended September 30, 2016.

With regard to the Petition, a trial date has been set for December 5, 2016, although the parties may elect arbitration prior to that date. With respect to the Arbitration, an initial hearing was held on November 9, 2016 at which the parties presented evidence supporting their position. The next hearing date related to Arbitration is November 16, 2016.

We do not expect the temporary injunction issued by the court related to the Litigation to have a material effect on our results of operations or financial condition. However, although GEL resumed normal delivery of crude oil and condensate to the Nixon Facility in July 2016, the adverse change in our relationship with Genesis has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has disrupted our normal business operations and diverted management’s focus away from operations. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet as of September 30, 2016.

Other Legal Matters. From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

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.

(20) Subsequent Events

Financial Covenant Defaults. As of September 30, 2016, LE and LRM were in violation of certain financial covenants related to the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.

By letter dated November 10, 2016, Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

ITEM 2.  

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In this Quarterly Report, references to “Blue Dolphin,” “we,” “us” and “our” are to Blue Dolphin Energy Company and its subsidiaries, unless otherwise indicated or the context otherwise requires. You should read the following discussion together with the financial statements and the related notes included elsewhere in this Quarterly Report, as well as with the risk factors, financial statements, and related notes included thereto in our Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016 and our Form 10-K for the fiscal year ended December 31, 2015 (the “Annual Report”).  

Forward Looking Statements

Certain statements included in this Quarterly Report, including in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1935. Forward-looking statements 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, commitments and contingencies, 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 and the other factors described under the heading “Risk Factors” in the Annual Report and this Quarterly Report:

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 Lazarus Energy Holdings, LLC (“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.

●

Failure to comply with certain financial covenants related to certain of our loan agreements.

●

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.

●

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

●

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.

●

An unfavorable outcome of litigation and contract-related disputes, which could have a material adverse effect on us.

●

Our dependence on LEH for financing and management of our properties.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

●

Potential refinery downtime, which could result in lost margin opportunity, increased maintenance costs, increased inventory, and a reduction in cash available for payment of our obligations.

●

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.

●

Volatility of refining margins.

●

Volatility of crude oil, other feedstocks, refined petroleum products, and fuel and utility services.

●

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.

●

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

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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.

●

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.

●

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 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. Information on or accessible through our website (http://www.blue-dolphin-energy.com) is not incorporated by reference in or otherwise made a part of this Quarterly Report.

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. As of September 30, 2016, the site contained approximately 842,000 bbls of crude oil, condensate, and refined petroleum product storage capacity. We are currently constructing an additional 256,000 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 refined petroleum products are primarily sold in the U.S. Jet fuel, our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing. With the opening of the Mexican diesel market to private companies, we began exporting low sulfur diesel to Mexico during the second quarter of 2016.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

The Nixon Facility uses light crude oil and condensate sourced in the Eagle Ford Shale as feedstock. 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 and nine months ended September 30, 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) Related Party Transactions,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Operating Agreement, and Jonathan Carroll.)

Our operations are conducted through the following active 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.

●

Blue Dolphin Services Co., a Texas corporation.

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

38

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Operating Risks

Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit 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 business and operational strategy will achieve anticipated outcomes.  Our operations, liquidity, and financial condition may be materially adversely affected if: (i) our strategy is not successful, (ii) our working capital requirements are not funded through Operations Payments by GEL TEX Marketing, LLC (“GEL”) under a Joint Marketing Agreement (the “Joint Marketing Agreement”), our profit share under the Joint Marketing Agreement, or certain advances from LEH, or (iii) we have future covenant violations under our loan agreements that are not waived.

For the three months ended September 30, 2016, we had a net loss of $1,938,551 compared to net income of $1,264,233 for the three months ended September 30, 2015. For the nine months ended September 30, 2016, we had a net loss of $7,250,371 compared to net income of $5,103,476 for the nine months ended September 30, 2015.

As of September 30, 2016, we had cash and cash equivalents and restricted cash (current portion) of $1,677,485 and $4,160,999, respectively. As of September 30, 2016, we had current assets of $22,404,232 and current liabilities (including the current portion of long-term debt) of $59,754,725, reflecting a working capital deficit of $37,350,493. Excluding the current portion of long-term debt, we had a working capital deficit of $5,229,711 as of September 30, 2016. Non-payment of Operations Payments to us by GEL under the Joint Marketing Agreement resulting from a contract-related dispute between the parties contributed to the working capital deficit as of September 30, 2016. (See “Part I. Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements and Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion related to Operations Payments, the Joint Marketing Agreement, and the contract-related dispute with Genesis.)

As of December 31, 2015, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively. As of December 31, 2015, we had current assets of $19,629,841 and current liabilities (including the current portion of long-term debt) of $20,228,648, reflecting a working capital deficit of $598,807.

In addition to the Joint Marketing Agreement, 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.   An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Part I. Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contract-related dispute with Genesis.)

As of September 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank (“Sovereign”). As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.  Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Part I. Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net and Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

39

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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 currently rely on Operations Payments and our profit share under the Joint Marketing Agreement and advances from LEH to fund our working capital requirements. If GEL does not advance Operations Payments and the profit share is insufficient to fund our working capital requirements, 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.

LEH also 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) Related Party Transactions” for additional disclosures related to LEH and the Operating Agreement.)

Relationship with 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. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for a summary of these agreements.) We currently have a contract-related dispute with GEL related to these agreements. In connection with this dispute, GEL significantly under delivered crude oil and condensate to the Nixon Facility under the Crude Supply Agreement during the second quarter of 2016. This resulted in significant refinery downtime and a significant decrease in refinery throughput, refinery production, and refined petroleum product sales for the nine months ended September 30, 2016. Although GEL resumed normal delivery of crude oil and condensate to the Nixon Facility in July 2016, the adverse change in our relationship with Genesis has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has disrupted our normal business operations and diverted management’s focus away from operations. (See “Part I. Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters” and “Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

41

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

GLOSSARY OF SELECTED FINANCIAL AND 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 that is being used in a refinery or transported through a pipeline. With respect to the Nixon Facility, the rate is calculated by dividing total refinery throughput or total refinery production on a bpd basis by the total capacity of the Nixon Facility (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 and/or unscheduled periods in which the Nixon Facility is not operating. Downtime may occur for a variety of reasons, including bad weather, power failures, preventive maintenance, equipment inspection, equipment repair due to mechanical failure, voluntary regulatory compliance measures, cessation or suspension by regulatory authorities, and inventory management.

Easement, Interest and Other Income. Reflects income related to 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 TEX Marketing, LLC (“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. Represents the number of days in a period in which the Nixon Facility operated. Operating days is calculated by subtracting downtime in a period from calendar days in the same period.

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 9/30/16

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

Consolidated Results

Three Months Ended September 30, 2016 (the “Current Three Months”) Compared to Three Months Ended September 30, 2015 (the “Prior Three Months”).

Total Revenue from Operations. For the Current Three Months we had total revenue from operations of $54,688,306 compared to total revenue from operations of $55,256,887 for the Prior Three Months. The slight increase in sales volume between the periods was offset by a decrease in commodity prices. The majority of revenue in the Current Three Months came from refined petroleum product sales, which generated revenue of $53,951,293, or approximately 99% of total revenue from operations, compared to $54,924,070, or more than 99% of total revenue from operations, in the Prior Three Months. We recognized $717,487 in tank rental revenue in the Current Three Months compared to $286,892 in the Prior Three Months. The significant increase in tank rental revenue between the Current Three Months and Prior Three Months related to the addition of a new tank rental lease agreement.

Cost of Refined Products Sold. Cost of refined products sold was $51,689,474 for the Current Three Months compared to $48,415,627 for the Prior Three Months. The approximate 7% increase in cost of refined products sold was primarily the result of an increase in sales volume.

Refinery Operating Expenses. We recorded refinery operating expenses of $3,153,646 in the Current Three Months compared to $2,953,528 in the Prior Three Months, an increase of approximately 7%. Refinery operating expenses per bbl of throughput were $2.77 in the Current Three Months compared to $2.66 in the Prior Three Months. The $0.11 increase in refinery operating expenses per bbl of throughput between the periods was a result of an increase in off-site tank leasing expense in the Current Three Months. (See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Related Party Transactions” for additional disclosures related to components of refinery operating expenses.)

JMA Profit Share. Under the Joint Marketing Agreement with GEL, Gross Profits are shared between the parties. If Gross Profits are positive, then the JMA Profit Share will reflect an expense to us. If Gross Profits are negative, then the JMA Profit Share will reflect a credit to us. For the Current Three Months, the JMA Profit Share was $965,627 compared to $1,435,376 for the Prior Three Months.  The significant reduction in JMA Profit Share between the periods was a result of the significant decrease in Gross Profits related to lower commodity prices. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement, JMA Profit Share, and Gross Profits.)

General and Administrative Expenses. We incurred general and administrative expenses of $891,210 in the Current Three Months compared to $312,365 in the Prior Three Months. The significant increase in general and administrative expenses in the Current Three Months compared to the Prior Three Months primarily related to legal fees associated with the Genesis litigation.

Depletion, Depreciation and Amortization. We recorded depletion, depreciation and amortization expenses of $504,719 in the Current Three Months compared to $414,837 in the Prior Three Months. The approximate 22% increase in depletion, depreciation and amortization expenses for the Current Three Months compared to the Prior Three Months primarily related to additional depreciable refinery assets that were placed in service.

Easement, Interest and Other Income. We recorded $157,840 in easement, interest and other income for the Current Three Months compared to $724,349 in the Prior Three Months. Easement, interest and other income in the Prior Three Months included recognition of a one-time gain of $660,000 related to settlement proceeds from a nearly two decades-old case involving Jack J. Grynberg and several defendants in the oil and gas industry, including Blue Dolphin Pipe Line Company (the “Grynberg Matter”).

Income Tax Benefit (Expense). We recognized an income tax benefit of $1,034,798 in the Current Three Months compared to an income tax expense of $688,403 in the Prior Three Months, which primarily related to deferred federal income taxes. The shift from an income tax expense to an income tax benefit between the periods was due to additional NOLs being generated in the Current Three Months, increasing deferred tax assets. (See “Part I, Financial Information, Item 1. Financial Statements – Note (15) Income Taxes” for additional disclosures related to income taxes.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Net Income (Loss). For the Current Three Months, we reported a net loss of $1,938,551, or a loss of $0.19 per share, compared to net income of $1,264,233, or income of $0.12 per share, for the Prior Three Months. The $0.31 per share decrease in net income between the periods was primarily the result of lower margins on refined petroleum products and higher refinery operating expenses, which was partially offset by an income tax benefit of $1,034,798 for the Current Three Months. Lower margins on refined petroleum products primarily related to a decrease in commodity prices.

Nine Months Ended September 30, 2016 (the “Current Nine Months”) Compared to Nine Months Ended September 30, 2015 (the “Prior Nine Months”).

Total Revenue from Operations. For the Current Nine Months we had total revenue from operations of $128,243,042 compared to total revenue from operations of $175,810,850 for the Prior Nine Months. The approximate 28% decrease in total revenue from operations between the periods was primarily the result of: (i) a decrease in commodity prices in the Current Nine Months compared to the Prior Nine Months and (ii) significant under delivery of crude oil and condensate by GEL under the Crude Supply Agreement during the second quarter of 2016, which contributed to a decrease in sales volume. The majority of our revenue in the Current Nine Months came from refined petroleum product sales, which generated revenue of $126,546,716, or more than 99% of total revenue from operations, compared to $174,830,292, or more than 99% of total revenue from operations, in the Prior Nine Months. We recognized $1,624,461 in tank rental revenue in the Current Nine Months compared to $860,676 in the Prior Nine Months. The significant increase in tank rental revenue between the Current Nine Months and Prior Nine Months related to the addition of a new tank rental lease agreement.

Cost of Refined Products Sold. Cost of refined products sold was $125,316,249 for the Current Nine Months compared to $151,604,774 for the Prior Nine Months. The approximate 17% decrease in cost of refined products sold was the result of decreases in commodity prices and sales volume in the Current Nine Months compared to the Prior Nine Months.

Refinery Operating Expenses. We recorded refinery operating expenses of $9,468,409 in the Current Nine Months compared to $8,420,650 in the Prior Nine Months, an increase of approximately 12%. Refinery operating expenses per bbl of throughput were $3.12 in the Current Nine Months compared to $2.73 in the Prior Nine Months. The $0.39 increase in refinery operating expenses per bbl of throughput between the periods was primarily the result of an increase in off-site tank leasing expense in the Current Nine Months. (See “Part I, Financial Information, Item 1. Financial Statements – Note (8) Related Party Transactions” for additional disclosures related to components of refinery operating expenses.)

JMA Profit Share. Under the Joint Marketing Agreement, Gross Profits are shared between the parties. If Gross Profits are positive, then the JMA Profit Share will reflect an expense to us. If Gross Profits are negative, then the JMA Profit Share will reflect a credit to us. For the Current Nine Months, the JMA Profit Share was $392,062 compared to $4,812,674 for the Prior Nine Months.  The significant reduction in JMA Profit Share between the periods was a result of the significant decrease in Gross Profits driven by lower commodity prices between the periods. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement, JMA Profit Share, and Gross Profits.)

General and Administrative Expenses. We incurred general and administrative expenses of $1,503,533 in the Current Nine Months compared to $1,058,267 in the Prior Nine Months. The significant increase in general and administrative expenses in the Current Nine Months compared to the Prior Nine Months primarily related to an increase in legal fees associated with the Genesis litigation.

Depletion, Depreciation and Amortization. We recorded depletion, depreciation and amortization expenses of $1,415,519 in the Current Nine Months compared to $1,217,005 in the Prior Nine Months. The approximate 16% increase in depletion, depreciation and amortization expenses for the Current Nine Months compared to the Prior Nine Months primarily related to additional depreciable refinery assets that were placed in service.

Easement, Interest and Other Income. We recorded $415,700 in easement, interest and other income for the Current Nine Months compared to $856,816 in the Prior Nine Months. Easement, interest and other income in the Prior Nine Months included recognition of a one-time gain of $660,000 related to the Grynberg Matter.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Income Tax Benefit (Expense). We recognized an income tax benefit of $3,735,040 in the Current Nine Months compared to an income tax expense of $2,778,750 in the Prior Nine Months, which primarily related to deferred federal income taxes. The shift from an income tax expense to an income tax benefit between the periods was due to additional NOLs being generated in the Current Nine Months, increasing deferred tax assets. (See “Part I, Financial Information, Item 1. Financial Statements – Note (15) Income Taxes” for additional disclosures related to income taxes.)

Net Income (Loss). For the Current Nine Months, we reported a net loss of $7,250,371, or a loss of $0.69 per share, compared to net income of $5,103,476, or income of $0.49 per share, for the Prior Nine Months. The $1.18 per share decrease in net income between the periods was the result of lower margins on refined petroleum products and higher refinery operating expenses, which was partially offset by an income tax benefit of $3,735,040 for the Current Nine Months. Lower margins on refined petroleum products primarily related to significant under delivery of crude oil and condensate by GEL under the Crude Supply Agreement during the second quarter of 2016 and a decrease in commodity prices.

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. (See “Part I, Financial Information, Item 1. Financial Statements” for comparative GAAP results.)

Adjusted EBITDA and EBITDA, Reconciliation to GAAP.

	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$54,668,780	$19,526	$-	$54,688,306	$55,210,962	$45,925	$-	$55,256,887
Less: cost of operations(1)	(55,495,575)	(129,160)	(238,755)	(55,863,490)	(51,444,705)	(114,675)	(236,816)	(51,796,196)
Other non-interest income(2)	-	156,396	-	156,396	-	62,500	660,000	722,500
Adjusted EBITDA	(826,795)	46,762	(238,755)	(1,018,788)	3,766,257	(6,250)	423,184	4,183,191
Less: JMA Profit Share(3)	(965,627)	-	-	(965,627)	(1,435,376)	-	-	(1,435,376)
EBITDA	$(1,792,422)	$46,762	$(238,755)	$(1,984,415)	$2,330,881	$(6,250)	$423,184	$2,747,815
Depletion, depreciation and
amortization				(504,719)				(414,837)
Interest expense, net				(484,215)				(380,342)
Income before income taxes				(2,973,349)				1,952,636
Income tax benefit (expense)				1,034,798				(688,403)
Net income				$(1,938,551)				$1,264,233

(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” 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” for further discussion of the Joint Marketing Agreement.)

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$128,171,177	$71,865	$-	$128,243,042	$175,690,968	$119,882	$-	$175,810,850
Less: cost of operations(1)	(135,452,537)	(383,124)	(695,786)	(136,531,447)	(160,208,576)	(296,291)	(928,331)	(161,433,198)
Other non-interest income(2)	-	412,061	-	412,061	-	187,500	660,000	847,500
Adjusted EBITDA	(7,281,360)	100,802	(695,786)	(7,876,344)	15,482,392	11,091	(268,331)	15,225,152
Less: JMA Profit Share(3)	(392,062)	-	-	(392,062)	(4,812,674)	-	-	(4,812,674)
EBITDA	$(7,673,422)	$100,802	$(695,786)	$(8,268,406)	$10,669,718	$11,091	$(268,331)	$10,412,478
Depletion, depreciation and
amortization				(1,415,519)				(1,217,005)
Interest expense, net				(1,301,486)				(1,313,247)
Income before income taxes				(10,985,411)				7,882,226
Income tax benefit (expense)				3,735,040				(2,778,750)
Net income				$(7,250,371)				$5,103,476

(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” 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” for further discussion of the Joint Marketing Agreement.)

Adjusted EBITDA and EBITDA, Current Three Months Compared to Prior Three Months.

For the Current Three Months, refinery operations adjusted EBITDA, total adjusted EBITDA, refinery operations EBITDA, and total EBITDA decreased significantly compared to the Prior Three Months. The significant decreases were primarily the result of lower margins from refined petroleum products in the Current Three Months, relating to a decrease in commodity prices. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

Refinery Operations Adjusted EBITDA. Refinery operations adjusted EBITDA for the Current Three Months was a loss of $826,795 compared to income of $3,766,257 for the Prior Three Months. This represented a decrease in refinery operations adjusted EBITDA of $4,593,052 for the Current Three Months compared to the Prior Three Months.

Total Adjusted EBITDA. Total adjusted EBITDA for the Current Three Months was a loss of $1,018,788 compared to income of $4,183,191 for the Prior Three Months. This represented a decrease in total adjusted EBITDA of $5,201,979 for the Current Three Months compared to the Prior Three Months.

Refinery Operations EBITDA. Refinery operations EBITDA for the Current Three Months was a loss of $1,792,422 compared to income of $2,330,881 for the Prior Three Months. This represented a decrease in refinery operations EBITDA of $4,123,303 for the Current Three Months compared to the Prior Three Months.

Total EBITDA. Total EBITDA for the Current Three Months was a loss of $1,984,415 compared to an income of $2,747,815 for the Prior Three Months. This represented a decrease in total EBITDA of $4,732,230 for the Current Three Months compared to the Prior Three Months.

46

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Adjusted EBITDA and EBITDA, Current Nine Months Compared to Prior Nine Months.

For the Current Nine Months, refinery operations adjusted EBITDA, total adjusted EBITDA, refinery operations EBITDA, and total EBITDA decreased significantly compared to the Prior Nine Months. The significant decreases were primarily the result of lower margins from refined petroleum products and higher refinery operating expenses in the Current Nine Months, relating to: (i) significant under delivery of crude oil and condensate by GEL under the Crude Supply Agreement during the second quarter of 2016 and (ii) a decrease in commodity prices. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as “Part II, Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

Refinery Operations Adjusted EBITDA. Refinery operations adjusted EBITDA for the Current Nine Months was a loss of $7,281,360 compared to income of $15,482,392 for the Prior Nine Months. This represented a decrease in refinery operations adjusted EBITDA of $22,763,752 for the Current Nine Months compared to the Prior Nine Months.

Total Adjusted EBITDA. Total adjusted EBITDA for the Current Nine Months was a loss of $7,876,344 compared to income of $15,225,152 for the Prior Nine Months. This represented a decrease in total adjusted EBITDA of $23,101,496 for the Current Nine Months compared to the Prior Nine Months.

Refinery Operations EBITDA. Refinery operations EBITDA for the Current Nine Months was a loss of $7,673,422 compared to income of $10,669,718 for the Prior Nine Months. This represented a decrease in refinery operations EBITDA of $18,343,140 for the Current Nine Months compared to the Prior Nine Months.

Total EBITDA. Total EBITDA for the Current Nine Months was a loss of $8,268,406 compared to an income of $10,412,478 for the Prior Nine Months. This represented a decrease in total EBITDA of $18,680,884 for the Current Nine Months compared to the Prior Nine Months.

Refinery Operating Income (Loss), Reconciliation to GAAP.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Total refined petroleum product sales	$53,951,293	$54,924,070	$126,546,716	$174,830,292
Less: Cost of refined petroleum products sold	(51,689,474)	(48,415,627)	(125,316,249)	(151,604,774)
Less: Refinery operating expenses	(3,153,646)	(2,953,528)	(9,468,409)	(8,420,650)
Refinery operating income before JMA Profit Share	(891,827)	3,554,915	(8,237,942)	14,804,868
Less: JMA Profit Share	(965,627)	(1,435,376)	(392,062)	(4,812,674)
Refinery operating income (loss)	$(1,857,454)	$2,119,539	$(8,630,004)	$9,992,194
Total refined petroleum product sales (bbls)	1,125,433	1,035,275	2,919,909	2,958,865

Refinery Operating Income (Loss), Current Three Months Compared to Prior Three Months and Current Nine Months Compared to Prior Nine Months.

For the Current Three Months, refinery operating loss totaled $1,857,454 compared to refinery operating income of $2,119,539 for the Prior Three Months, representing a decrease of $3,976,993. Refinery operating income for the Current Three Months declined compared to the Prior Three Months as a result of lower margins on refined petroleum products.

For the Current Nine Months, refinery operating loss totaled $8,630,004 compared to refinery operating income of $9,992,194 for the Prior Nine Months, representing a decrease of $18,622,198. Refinery operating income (loss) for the Current Nine Months decreased significantly compared to the prior period primarily as a result of lower margins from refined petroleum products and higher refinery operating expenses, which related to several factors including: (i) significant under delivery of crude oil and condensate by GEL under the Crude Supply Agreement during the second quarter of 2016 and (ii) a decrease in commodity prices. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

47

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Refinery Operations Business Segment Results

During the Current Nine Months, GEL significantly under delivered crude oil and condensate to the Nixon Facility under the Crude Supply Agreement. This resulted in significant refinery downtime and a significant decrease in refinery throughput and refinery production in the Current Nine Months. Although GEL resumed normal delivery of crude oil and condensate to the Nixon Facility in July 2016, the adverse change in our relationship with Genesis has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has disrupted our normal business operations and diverted management’s focus away from operations. (See “Part I. Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

Refinery Throughput and Production Data.

Following are refinery operational metrics for the Nixon Facility:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Calendar Days	92	92	274	273
Refinery downtime	(1)	(5)	(30)	(16)
Operating Days	91	87	244	257
Total refinery throughput (bbls)	1,139,458	1,109,411	3,034,256	3,086,749
Operating days:
bpd	12,522	12,752	12,435	12,011
Capacity utilization rate	83.5%	85.0%	82.9%	80.1%
Calendar days:
bpd	12,385	12,059	11,074	11,307
Capacity utilization rate	82.6%	80.4%	73.8%	75.4%
Total refinery production (bbls)	1,106,415	1,084,246	2,948,281	3,024,579
Operating days:
bpd	12,158	12,463	12,083	11,769
Capacity utilization rate	81.1%	83.1%	80.6%	78.5%
Calendar days:
bpd	12,026	11,785	10,760	11,079
Capacity utilization rate	80.2%	78.6%	71.7%	73.9%

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

48

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Current Three Months Compared to Prior Three Months.

Refinery Downtime. The Nixon Facility operated for a total of 91 days in the Current Three Months, reflecting a single day of refinery downtime. Comparatively, the Nixon Facility operated for a total of 87 days in the Prior Three Months, reflecting 5 days of refinery downtime. During the Current Three Months, the single day of refinery downtime related to maintenance. Refinery downtime in the Prior Three Months related to unscheduled maintenance and a maintenance turnaround. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

Total Refinery Throughput. On an operating day basis, the Nixon Facility processed 12,522 bpd of crude oil and condensate for the Current Three Months compared to 12,752 bpd of crude oil and condensate for the Prior Three Months, which represented a slight decrease of 230 bpd.

Total Refinery Production. On an operating day basis, the Nixon Facility produced 12,158 bpd of refined petroleum products for the Current Three Months compared to 12,463 bpd of refined petroleum products for the Prior Three Months, which represented a slight decrease of 305 bpd.

Capacity Utilization Rate. On an operating day basis, the capacity utilization rate for: (i) refinery throughput for the Current Three Months was 83.5% compared to 85.0% for the Prior Three Months, reflecting a less than 2% decrease and (ii) refinery production for the Current Three Months was 81.1% compared to 83.1% for the Prior Three Months, reflecting an approximate 2% decrease. Capacity utilization rate between the periods decreased as a result of lower total refinery throughput and total refinery production on a barrel per day basis.

Current Nine Months Compared to Prior Nine Months.

Refinery Downtime. The Nixon Facility operated for a total of 244 days in the Current Nine Months, reflecting 30 days of refinery downtime. Comparatively, the Nixon Facility operated for a total of 257 days in the Prior Nine Months, reflecting 16 days of refinery downtime. The significant decrease in operating days between the periods was primarily the result of significant under delivery of crude oil and condensate by GEL under the Crude Supply Agreement during the second quarter of 2016. Refinery downtime in the Prior Nine Months related to unscheduled maintenance and a maintenance turnaround. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion of the current contract-related dispute with Genesis.)

Total Refinery Throughput. On an operating day basis, the Nixon Facility processed 12,435 bpd of crude oil and condensate for the Current Nine Months compared to 12,011 bpd of crude oil and condensate for the Prior Nine Months, which represented an increase of 424 bpd.

Total Refinery Production. On an operating day basis, the Nixon Facility produced 12,083 bpd of refined petroleum products for the Current Nine Months compared to 11,769 bpd of refined petroleum products for the Prior Nine Months, which represented a slight increase of 314 bpd.

Capacity Utilization Rate. On an operating day basis, the capacity utilization rate for: (i) refinery throughput for the Current Nine Months was 82.9% compared to 80.1% for the Prior Nine Months, reflecting an approximate 3% increase and (ii) refinery production for the Current Nine Months was 80.6% compared to 78.5% for the Prior Nine Months, reflecting an approximate 3% increase. Capacity utilization rate between the periods increased as a result of higher total refinery throughput and total refinery production on a barrel per day basis.

Refined Petroleum Product Sales Summary.

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

49

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Refined Petroleum Product Economic Hedges.

Under our inventory risk management policy, commodity futures contracts are used to mitigate the volatile change in value for certain of our refined petroleum product inventories. For the Current Three Months, our refinery operations business segment recognized a gain of $2,299,678 on settled transactions and a loss of $1,528,840 on the change in value of open contracts from June 30, 2016 to September 30, 2016. For the Prior Three Months, our refinery operations business segment recognized a gain of $2,101,041 on settled transactions and a gain of $104,250 on the change in value of open contracts from June 30, 2015 to September 30, 2015. Although commodity price increases were similar between the periods, larger volumes were hedged in the Current Three Months compared to the Prior Three Months.

For the Current Nine Months, our refinery operations business segment recognized a loss of $1,445,244 on settled transactions and a loss of $1,143,490 on the change in value of open contracts from December 31, 2015 to September 30, 2016. For the Prior Nine Months, our refinery operations business segment recognized a gain of $2,125,332 on settled transactions and a loss of $362,750 on the change in value of open contracts from December 31, 2014 to September 30, 2015. Although commodity price increases were similar between the periods, larger volumes were hedged in the Current Nine Months compared to the Prior Nine Months.

Liquidity and Capital Resources

For the three months ended September 30, 2016, we had a net loss of $1,938,551 compared to net income of $1,264,233 for the three months ended September 30, 2015. For the nine months ended September 30, 2016, we had a net loss of $7,250,371 compared to net income of $5,103,476 for the nine months ended September 30, 2015.

As of September 30, 2016, we had cash and cash equivalents and restricted cash (current portion) of $1,677,485 and $4,160,999, respectively. As of September 30, 2016, we had current assets of $22,404,232 and current liabilities (including the current portion of long-term debt) of $59,754,725, reflecting a working capital deficit of $37,350,493. Excluding the current portion of long-term debt, we had a working capital deficit of $5,229,711 as of September 30, 2016. Non-payment of Operations Payments to us by GEL under the Joint Marketing Agreement resulting from a contract-related dispute between the parties contributed to the working capital deficit as of September 30, 2016. (See “Part I. Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements and Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a discussion related to Operations Payments, Joint Marketing Agreement, and the contract-related dispute with Genesis.)

As of December 31, 2015, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively. As of December 31, 2015, we had current assets of $19,629,841 and current liabilities (including the current portion of long-term debt) of $20,228,648, reflecting a working capital deficit of $598,807.

As of September 30, 2016, we were in violation of certain financial covenants in loan agreements with Sovereign. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.   Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Part I, Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net and Note (20) Subsequent Events” for additional disclosures related to Sovereign, our long-term debt, and financial covenant violations.)

Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit 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 business and operational strategy will achieve anticipated outcomes.  Our operations, liquidity, and financial condition may be materially adversely affected if: (i) our strategy is not successful, (ii) our working capital requirements are not funded through Operations Payments, our profit share under the Joint Marketing Agreement, or certain advances from LEH, or (iii) we have future covenant violations under our loan agreements that are not waived.

(See “Capital Spending” within the “Liquidity and Capital Resources” section for a discussion of our plans to expand the Nixon Facility.)

50

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Cash Flow

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Cash flow from operations
Adjusted income (loss) from operations	$(879,483)	$2,231,898	$(8,335,348)	$9,859,360
Change in assets and current liabilities	(5,493,430)	(1,147,370)	3,657,961	(3,900,092)
Total cash flow from operations	(6,372,913)	1,084,528	(4,677,387)	5,959,268
Cash inflows (outflows)
Proceeds from issuance of debt	6,898,931	-	6,898,931	28,000,000
Payments on debt	(469,541)	(403,561)	(1,414,406)	(9,474,720)
Change in restricted cash for investing activities	3,595,042	478,562	11,257,897	(13,021,438)
Capital expenditures	(4,182,747)	(2,355,811)	(11,255,725)	(8,156,298)
Change in restricted cash for financing activities	25,151	206,127	(985,700)	(3,081,686)
Total cash outflows	5,866,836	(2,074,683)	4,500,997	(5,734,142)
Total change in cash flows	$(506,077)	$(990,155)	$(176,390)	$225,126

We experienced negative cash flow from operations of $6,372,913 for the Current Three Months compared to positive cash flow from operations of $1,084,528 for the Prior Three Months, reflecting a $7,457,441 decrease in cash flow from operations between the periods. The decrease was primarily the result of a net loss increase, as well as a decrease in accounts payable. This was slightly offset by a decrease in inventory and a decrease in accounts receivable.

We experienced negative cash flow from operations of $4,677,387 compared to positive cash flow from operations of $5,959,268 for the Prior Nine Months, reflecting a $10,636,655 decrease in cash flow from operations between the periods. The decrease was primarily the result of sustaining net losses for the Current Nine Months compared to net income for the Prior Nine Months. The net loss for the Current Nine Months was primarily the result of lower margins from refined petroleum products and higher refinery operating expenses, which primarily related to a decrease in commodity prices. These negative impacts on cash flow were partially mitigated by a significant increase in accounts payable, accrued expenses, and other liabilities.

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.

During the Current Nine Months, we:

●

Completed construction of an additional 444,000 bbls of petroleum storage capacity at the Nixon Facility.

●

Increased HOBM orders from new customers by barge.

●

Increased exports of low sulfur diesel to Mexico via truck.

51

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

We are constructing an additional 256,000 bbls of petroleum storage at the Nixon Facility. When expansion of the Nixon Facility is complete, total crude oil, condensate, and refined petroleum product storage capacity will exceed 1,000,000 bbls. Capital expenditures at the Nixon Facility are being funded primarily through borrowings. Amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment and to fund construction contingencies are reflected in restricted cash (current portion). Restricted cash (current portion) totaled $4,160,999 and $3,175,299 as of September 30, 2016 and December 31, 2015, respectively. Amounts held in our disbursement account with Sovereign for payment of construction related expenses to build new petroleum storage tanks are reflected in restricted cash, noncurrent. Restricted cash, noncurrent totaled $4,358,581 and $15,616,478 as of September 30, 2016 and December 31, 2015, respectively. (See “Part I, Financial Information, Item 1. Financial Statements – Note (9) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.)

Capital expenditures in the Current Three Months totaled $4,182,747 compared to $2,355,811 in the Prior Three Months, primarily reflecting the completed construction of 122,000 bbls of petroleum storage capacity at the Nixon Facility in the period. Capital expenditures in the Current Nine Months totaled $11,255,725 compared to $8,156,298 in the Prior Nine Months, primarily reflecting the completed construction of 444,000 bbls of petroleum storage capacity at the Nixon Facility in the period.

Contractual Obligations

Related Party.

We are a party to agreements with Ingleside Crude, LLC (“Ingleside”), LEH, and Jonathan Carroll. Ingleside is a related party of LEH and Jonathan Carroll. 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. We believe these related party transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions.

As of September 30, 2016, accounts receivable related to LEH totaled $2,869,805.

Unsettled reimbursements associated with the Operating Agreement and reflected within prepaid expenses and other current assets as of the dates indicated were as follows:

	September 30,	December 31,
	2016	2015
LEH	$-	$624,570
	$-	$624,570

Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
LEH	$5,797,172	$-
Ingleside	679,385
Jonathan Carroll	422,374
	6,898,931	-
Less: Long-term debt,
related party,
current portion	(500,000)	-
	$6,398,931	$-

52

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
LEH	$80,000	$-
	80,000	-
Less: Interest payable,
current portion	(80,000)	-
	$-	$-

Accounts payable, related party associated with the Amended and Restated Tank Lease Agreement as of the dates indicated was as follows:

	September 30,	December 31,
	2016	2015
Ingleside	$-	$300,000
	$-	$300,000

Refinery operating expenses associated with the Operating Agreement and Amended and Restated Tank Lease Agreement for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	Amount	Per bbl	Amount	Per bbl	Amount	Per bbl	Amount	Per bbl
LEH	$3,028,646	$2.66	$2,953,528	$2.66	$8,618,409	$2.84	$8,420,650	$2.73
Ingleside	125,000	$0.11	-	$0.00	850,000	$0.28	-	$0.00
	$3,153,646	$2.77	$2,953,528	$2.66	$9,468,409	$3.12	$8,420,650	$2.73

Remainder of Page Intentionally Left Blank

53

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Revenue associated with the Product Sales Agreement and Terminal Services Agreement for the periods indicated was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Refined petroleum product sales
LEH	$14,536,997	$-	$23,449,071	$-
Other customers	39,414,296	54,924,070	103,097,645	174,830,292
Total refined petroleum product sales	53,951,293	54,924,070	126,546,716	174,830,292
Tank rental revenue
LEH	426,000	-	750,000	-
Other customers	291,487	286,892	874,461	860,676
Total tank rental revenue	717,487	286,892	1,624,461	860,676
Pipeline operations
Other customers	19,526	45,925	71,865	119,882
Total revenue from operations	$54,688,306	$55,256,887	$128,243,042	$175,810,850

Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Jonathan Carroll	$172,300	$165,008	$522,931	$165,008
LEH	80,000	-	80,000	-
	$252,300	$165,008	$602,931	$165,008

(See “Part I, Financial Information, Item 1. Financial Statements – Note (5) Prepaid Expenses and Other Current Assets and Note (8) Related Party Transactions” for additional disclosures related to Ingleside, LEH, and Jonathan Carroll.)

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.  An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Part I, Financial Information, Item 1. Financial Statements – Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contract-related dispute with Genesis.)

Supplemental Pipeline Bonds.

As of September 30, 2016, LE and LRM were in violation of certain financial covenants related to the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Part I, Financial Information, Item 1. Financial Statements - Note (1) Organization - Operating Risks, Note (9) Long-Term Debt, Net, and Note (20) Subsequent Events” for additional disclosures related to long-term debt financial covenant violations.)

54

BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

Indebtedness

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

	September 30,	December 31,
	2016	2015
First Term Loan Due 2034	$24,111,986	$24,643,081
Second Term Loan Due 2034	9,797,549	10,000,000
Notre Dame Debt	1,300,000	1,300,000
Term Loan Due 2017	369,987	924,969
Capital Leases	178,741	304,618
	35,758,263	37,172,668
Less: Unamoritized debt issue costs	(2,295,118)	(2,391,482)
	$33,463,145	$34,781,186

As of September 30, 2016, LE and LRM were in violation of certain financial covenants related to the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Part I, Financial Information, Item 1. Financial Statements – Note (1) Organization – Operating Risks, Note (9) Long-Term Debt, Net, and Note (20) Subsequent Events” for additional disclosures related to long-term debt financial covenant violations.)

See “Contractual Obligations – Related Party” within the Liquidity and Capital Resources section for additional disclosures with respect to related party indebtedness.

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

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 and nine months ended September 30, 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

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

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.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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

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 reporting 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” for further information related to income taxes.)

Recently Adopted AccountingGuidance

The Financial Accounting Standards Board (“FASB”) issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB Accounting Standards Codification, including changes to non-authoritative SEC content. For the three and nine months ended September 30, 2016, we adopted the following recently issued ASU’s:

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.

ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has 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 9/30/16

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 and nine months ended September 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. (See “Part II, Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure” and “Part II, Item 9A. Controls and Procedures” of our Annual Report for a discussion related to controls and procedures.)

Remainder of Page Intentionally Left Blank

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Genesis Contract-Related Dispute

We are party to a variety of contracts and agreements with Genesis Energy, LLC “(Genesis”) and its affiliates, including GEL Tex Marketing, LLC (“GEL”) that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services.

In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the “Petition”) against Lazarus Energy, LLC ("LE") and Lazarus Energy Holdings, LLC ("LEH"). The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, in connection with an agreement by LEH to supply jet fuel acquired from LE to a customer. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GEL’s claims in the Petition are without merit and intends to defend the matter vigorously.

In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of the Dispute Resolution Agreement between the parties (the “Arbitration”). The Arbitration alleges that GEL breached the Crude Supply Agreement related to:

(i)

failure to provide crude oil and condensate at cost as defined in the Crude Supply Agreement, and

(ii)

significant under delivery of crude oil and condensate, resulting in significant refinery downtime and a significant decrease in refinery throughput, refinery production, and refined petroleum product sales for the three and nine months ended September 30, 2016.

With regard to the Petition, a trial date has been set for December 5, 2016, although the parties may elect arbitration prior to that date. With respect to the Arbitration, an initial hearing was held on November 9, 2016 at which the parties presented evidence supporting their position. The next hearing date related to Arbitration is November 16, 2016.

We do not expect the temporary injunction issued by the court related to the Litigation to have a material effect on our results of operations or financial condition. However, although GEL resumed normal delivery of crude oil and condensate to the Nixon Facility in July 2016, the adverse change in our relationship with Genesis has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has disrupted our normal business operations and diverted management’s focus away from operations. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet as of September 30, 2016.

Other Legal Matters

From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

ITEM 1A.  RISK FACTORS

In addition to the other information set forth in this Form 10-Q for the quarterly period ended September 30, 2016 (this “Quarterly Report”), careful consideration should be given to the risk factors discussed under “Part I, Item 1A. Risk Factors” and elsewhere in our Form 10-K for the fiscal year ended December 31, 2015 (the “Annual Report”) and our Form 10-Q’s for the quarterly periods ended March 31, 2016 and June 30, 2016. 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 risk factor noted below, there have been no material changes in our assessment of our risk factors from those set forth in our Annual Report and our Form 10-Q for the quarterly period ended June 30, 2016.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

An unfavorable outcome of litigation and contract-related disputes could have a material adverse effect on us.

We are a party to a contract related dispute with Genesis and GEL. Litigation and contract related disputes through arbitration can be expensive, lengthy, disruptive to normal business operations, and divert management’s focus away from operations. Moreover, the outcomes of complex legal proceedings or contract-related disputes can be difficult to predict. An unfavorable resolution of a legal proceeding or contract-related dispute could have a material adverse effect on our business, results of operations, financial condition, and reputation.

We record provisions for pending litigation when we determine that an unfavorable outcome is likely and the loss can reasonably be estimated. Due to the inherent uncertain nature of litigation, the ultimate outcome or actual cost of settlement may materially differ from estimates. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet as of September 30, 2016.

We are in violation of certain financial covenants in secured loan agreements with Sovereign Bank (“Sovereign”), and our failure to comply could materially and adversely affect our operating results and our financial condition.

As of September 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, $30,423,203 of debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets as of September 30, 2016, due to the uncertainty of our ability to meet the financial covenants in the future.

There can be no assurance that: (i) our assets or cash flow would be sufficient to fully repay borrowings under our outstanding long-term debt, either upon maturity or if accelerated, (ii) we would be able to refinance or restructure the payments on the long-term debt, and/or (ii) Sovereign will provide future waivers. 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 Sovereign may exercise any rights and remedies available under the loan agreement(s). Any such action by Sovereign would have a material adverse effect on our financial condition and ability to continue as a going concern. (See “Part I., Financial Information, Item 1. Financial Statements ñ Note (9), Long-Term Debt, Net and Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

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” for disclosures related to defaults on our debt.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

Item 1.01  Entry into a Material Definitive Agreement.

LEH Note

On September 30, 2016, we entered into a promissory note with LEH in the original principal amount of $1,797,172 (the “LEH Note”). The LEH Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.

Ingleside Note

On September 30, 2016, we entered into a promissory note with Ingleside Crude, LLC in the original principal amount of $679,385 (the “Ingleside Note”). The Ingleside Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

Carroll Note

On September 30, 2016, we entered into a promissory note with Jonathan Carroll in the original principal amount of $422,374 (the “Carroll Note”). The Carroll Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Carroll Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty.

The foregoing summarizes the material terms of the LEH Note, Ingleside Note, and Carroll Note. This summary does not purport to be complete and is qualified in its entirety by reference to the full text of the respective notes, which are filed as exhibits to this Quarterly Report.

LEH, our controlling shareholder, owns approximately 81% of our common stock, par value $0.01 per share. Jonathan Carroll, Chairman of the Board of Directors, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. Ingleside is a related party of LEH and Jonathan Carroll.

Item 2.03.  Creation of a Direct Financial Obligation or an Obligation under an Off-Balance SheetArrangement of a Registrant.

The information set forth in Item 1.01 above is incorporated by reference in this Item 2.03 in its entirety.

ITEM 6.  EXHIBITS

Exhibits Index

No.  Description 

10.1*	Loan and Security Agreement by and between Lazarus Energy Holdings, LLC and Blue Dolphin Pipe Line Company dated August 15, 2016 (filed as Exhibit 10.1 to Blue Dolphin’s Form 8-K as filed with the SEC on August 15, 2016).
10.2*	Promissory Note by and between Lazarus Energy Holdings, LLC and Blue Dolphin Pipe Line Company dated August 15, 2016 (filed as Exhibit 10.2 to Blue Dolphin’s Form 8-K as filed with the SEC on August 15, 2016).
10.3*	Deed of Trust, Mortgage, Security Agreement, Assignment of Leases and Rents, Financing Statement and Fixture Filing for Blue Dolphin Pipe Line Company dated August 15, 2016 (filed as Exhibit 10.3 to Blue Dolphin’s Form 8-K as filed with the SEC on August 15, 2016).
10.4*	Collateral Assignment of Master Easement Agreement by Blue Dolphin Pipe Line Company for the benefit of Lazarus Energy Holdings, LLC dated August 15, 2016 (filed as Exhibit 10.4 to Blue Dolphin’s Form 8-K as filed with the SEC on August 15, 2016).
10.5	Letter dated November 10, 2016 from Sovereign Bank to Lazarus Energy, LLC and Lazarus Refining & Marketing, LLC.
10.6	Promissory Note between Blue Dolphin Energy Company and Lazarus Energy Holdings, LLC in the principal amount of $1,797,172 dated September 30, 2016.
10.7	Promissory Note between Blue Dolphin Energy Company and Ingleside Crude, LLC in the principal amount of $679,385 dated September 30, 2016.
10.8	Promissory Note between Blue Dolphin Energy Company and Lazarus Capital, LLC in the principal amount of $422,374 dated September 30, 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.

*            

Exhibit incorporated by reference as indicated; all other exhibits are filed herewith.

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BLUE DOLPHIN ENERGY COMPANY FORM 10-Q 9/30/16

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: November 14, 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: November 14, 2016	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)

62

EX-10.5

November 10, 2016

SOVEREIGN BANK

Mr. Jonathan Carroll

Lazarus Energy LLC and Lazarus Refining & Marketing, LLC

801 Travis Street, Suite 2100

Houston, TX 77002

Lazarus Energy LLC ("LE") and Lazarus Refining & Marketing, LLC ("LRM", and collectively, with LE, "Lazarus") have three outstanding loans (collectively, the "Loans") from Sovereign Bank ("Bank"). The Loans are evidenced by, among other documents, (i) three Loan Agreements (collectively, the "Loan Agreements") dated May 2, 2014, June 22, 2015, and December 4, 2015, respectively. As of the quarter ending September 30, 2016, Lazarus is in breach of the following covenants specified in the Loan Agreements, as specified below (collectively, the "Covenant Default"):

1. Loan Agreement dated June 22, 2015 between Bank and LE:

a.Section 4.2 (c) combined Current Ratio of not less than 1.0 to 1.0;

b.Section 4.2 (e) combined Debt Service Coverage Ratio of not less than 1 50 to 1.0;

2. Loan Agreement dated December 4, 2015 between Bank and LRM:

a.Section 4.2 (c) combined Current Ratio of not less than 1.0 to 1.0;

b.Section 4.2 (e) combined Debt Service Coverage Ratio of not less than 1.50 to 1.0;

Subject to the agreement and concurrence of the United States Department of Agriculture ("USDA") that Bank's waiver of the Covenant Default shall not impair or void any of the USDA agreements and guarantees relating to the Loans, Bank hereby waives (the "Waiver") the Covenant Default as to only the quarter ending September 30, 2016. Except for the foregoing, Bank hereby expressly reserves and preserves all of Bank's rights, remedies and recourses under the Loan Agreements and all of the other documents evidencing, governing, guaranteeing and/or securing the loans (all such documents, collectively, with the Loan Agreements, the "Loan Documents"), including, without limitation, Bank's rights with respect to any other breaches or defaults under the Loan Documents which may be now existing, or which hereafter occur.

This Waiver is made as a courtesy to Lazarus, and shall not constitute a course of dealing or entitle Lazarus to any further waivers or forbearances. Bank hereby demands strict performance with all terms and conditions of the Loan Documents.

SOVEREIGN BANK

By:/s/ KATHRYN WALKER

Name: Kathryn Walker

Title: Senior Vice President

Page 1 of 1

 17950 Preston Road
 Suite 500
 Dallas, Texas 75252
 ph. 214.242.1900
 www.banksovereign.com

EX-10.6

Exhibit 10.6

NOTE

September 30, 2016

FOR VALUE RECEIVED, BLUE DOLPHIN ENERGY COMPANY (the "Borrower"), hereby promises to pay to the order of LAZARUS ENERGY HOLDINGS, LLC ("Payee"), the principal sum of $1,797,171.61 pursuant to the terms and conditions set forth herein.

PAYMENT OF PRINCIPAL.  The principal amount of this Promissory Note (the "Note") and any accrued but unpaid interest shall be due and payable on January 1, 2018. 

INTEREST.  This Note shall bear interest, compounded annually, at eight percent.

PREPAYMENT.  The Borrower shall have the right at any time and from time to time to prepay this Note in whole or in part without premium or penalty.

REMEDIES.  No delay or omission on part of the holder of this Note in exercising any right hereunder shall operate as a waiver of any such right or of any other right of such holder, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.  The rights and remedies of the Payee shall be cumulative and may be pursued singly, successively, or together, in the sole discretion of the Payee.

SUBORDINATION.  The Borrower's obligations under this Note are subordinated to all indebtedness of Borrower to any unrelated third party lender to the extent such indebtedness is outstanding on the date of this Note and such subordination is required under the loan documents providing for such indebtedness.

EXPENSES.  In the event any payment under this Note is not paid when due, the Borrower agrees to pay, in addition to the principal and interest hereunder, reasonable attorneys' fees not exceeding a sum equal to 15% of the then outstanding balance owing on the Note, plus all other reasonable expenses incurred by Payee in exercising any of its rights and remedies upon default.

GOVERNING LAW.  This Note shall be governed by, and construed in accordance with, the laws of the State of Texas.

IN WITNESS WHEREOF, Borrower has executed this Note as of the day and year first above written.

____/s/ JONATHAN P. CARROLL__(LENDER SIGNATURE)

LAZARUS ENERGY HOLDINGS, LLC                                                                                                                                            September 30, 2016

____/s/ TOMMY L. BYRD___(BORROWER SIGNATURE)

BLUE DOLPHIN ENERGY COMPANY                                                                                                                                            September 30, 2016

EX-10.7

Exhibit 10.7

NOTE

September 30, 2016

FOR VALUE RECEIVED, BLUE DOLPHIN ENERGY COMPANY (the "Borrower"), hereby promises to pay to the order of INGLESIDE CRUDE, LLC ("Payee"), the principal sum of $679,385.69 pursuant to the terms and conditions set forth herein.

PAYMENT OF PRINCIPAL.  The principal amount of this Promissory Note (the "Note") and any accrued but unpaid interest shall be due and payable on January 1, 2018. 

INTEREST.  This Note shall bear interest, compounded annually, at eight percent.

PREPAYMENT.  The Borrower shall have the right at any time and from time to time to prepay this Note in whole or in part without premium or penalty.

REMEDIES.  No delay or omission on part of the holder of this Note in exercising any right hereunder shall operate as a waiver of any such right or of any other right of such holder, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.  The rights and remedies of the Payee shall be cumulative and may be pursued singly, successively, or together, in the sole discretion of the Payee.

SUBORDINATION.  The Borrower's obligations under this Note are subordinated to all indebtedness of Borrower to any unrelated third party lender to the extent such indebtedness is outstanding on the date of this Note and such subordination is required under the loan documents providing for such indebtedness.

EXPENSES.  In the event any payment under this Note is not paid when due, the Borrower agrees to pay, in addition to the principal and interest hereunder, reasonable attorneys' fees not exceeding a sum equal to 15% of the then outstanding balance owing on the Note, plus all other reasonable expenses incurred by Payee in exercising any of its rights and remedies upon default.

GOVERNING LAW.  This Note shall be governed by, and construed in accordance with, the laws of the State of Texas.

IN WITNESS WHEREOF, Borrower has executed this Note as of the day and year first above written.

___/s/ JONATHAN P. CARROLL__(LENDER SIGNATURE)

INGLESIDE CRUDE, LLC                                                                                                                                  September 30, 2016

__/s/ TOMMY L. BYRD__(BORROWER SIGNATURE)

BLUE DOLPHIN ENERGY COMPANY                                                                                                            September 30, 2016

EX-10.8

Exhibit 10.8

NOTE

September 30, 2016

FOR VALUE RECEIVED, BLUE DOLPHIN ENERGY COMPANY (the "Borrower"), hereby promises to pay to the order of LAZARUS CAPITAL, LLC ("Payee"), the principal sum of $422,373.79 pursuant to the terms and conditions set forth herein.

PAYMENT OF PRINCIPAL.  The principal amount of this Promissory Note (the "Note") and any accrued but unpaid interest shall be due and payable on January 1, 2018. 

INTEREST.  This Note shall bear interest, compounded annually, at eight percent.

PREPAYMENT.  The Borrower shall have the right at any time and from time to time to prepay this Note in whole or in part without premium or penalty.

REMEDIES.  No delay or omission on part of the holder of this Note in exercising any right hereunder shall operate as a waiver of any such right or of any other right of such holder, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.  The rights and remedies of the Payee shall be cumulative and may be pursued singly, successively, or together, in the sole discretion of the Payee.

SUBORDINATION.  The Borrower's obligations under this Note are subordinated to all indebtedness of Borrower to any unrelated third party lender to the extent such indebtedness is outstanding on the date of this Note and such subordination is required under the loan documents providing for such indebtedness.

EXPENSES.  In the event any payment under this Note is not paid when due, the Borrower agrees to pay, in addition to the principal and interest hereunder, reasonable attorneys' fees not exceeding a sum equal to 15% of the then outstanding balance owing on the Note, plus all other reasonable expenses incurred by Payee in exercising any of its rights and remedies upon default.

GOVERNING LAW.  This Note shall be governed by, and construed in accordance with, the laws of the State of Texas.

IN WITNESS WHEREOF, Borrower has executed this Note as of the day and year first above written.

___/s/ JONATHAN P. CARROLL____(LENDER SIGNATURE)

LAZARUS CAPITAL, LLC                                                                                                                       September 30, 2016

__/s/ TOMMY L. BYRD___(BORROWER SIGNATURE)

BLUE DOLPHIN ENERGY COMPANY                                                                                                 September 30, 2016

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: November 14, 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: November 14, 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 September 30, 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: November 14, 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 September 30, 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: November 14, 2016	By:	/s/ TOMMY L. BYRD
		Tommy L. Byrd
		Chief Financial Officer, Treasurer and Assistant Secretary
		(Principal Financial Officer)

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 14, 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	Sep. 30, 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		10,474,714
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2016

XML

Consolidated Balance Sheets (Unaudited) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 1,677,485	$ 1,853,875
Restricted cash	4,160,999	3,175,299
Accounts receivable, net	7,412,697	5,457,245
Prepaid expenses and other current assets	196,101	939,690
Deposits	136,970	395,414
Inventory	8,819,980	7,808,318
Total current assets	22,404,232	19,629,841
Total property and equipment, net	61,283,727	48,841,812
Restricted cash, noncurrent	4,358,581	15,616,478
Surety bonds	710,000	1,022,000
Trade name	303,346	303,346
Deferred tax assets, net	7,342,277	3,607,237
Total long-term assets	73,997,931	69,390,873
TOTAL ASSETS	96,402,163	89,020,714
CURRENT LIABILITIES
Accounts payable	23,886,185	14,882,714
Accounts payable, related party		300,000
Asset retirement obligations, current portion	25,972	38,644
Accrued expenses and other current liabilities	3,063,080	2,990,891
Interest payable, current portion	158,706	81,467
Long-term debt less unamortized debt issue costs, current portion	32,120,782	1,934,932
Long-term debt, related party, current portion	500,000
Total current liabilities	59,754,725	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,983,042	1,947,220
Deferred revenues and expenses	93,814	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,342,363	32,846,254
Long-term debt, related party, net of current portion	6,398,931
Long-term interest payable, net of current portion	1,638,952	1,482,801
Total long-term liabilities	11,457,102	36,401,360
TOTAL LIABILITIES	71,211,827	56,630,008
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,614,715 and 10,603,802 shares issued at September 30, 2016 and December 31, 2015, respectively)	106,148	106,038
Additional paid-in capital	36,788,628	36,738,737
Accumulated deficit	(10,904,440)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	25,190,336	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 96,402,163	$ 89,020,714

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Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 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	10,614,715	10,603,802
Common stock, shares outstanding	10,614,715	10,603,802
Treasury stock, shares	150,000	150,000

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Consolidated Statements of Operations (Unaudited) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 53,951,293	$ 54,924,070	$ 126,546,716	$ 174,830,292
Tank rental revenue	717,487	286,892	1,624,461	860,676
Pipeline operations	19,526	45,925	71,865	119,882
Total revenue from operations	54,688,306	55,256,887	128,243,042	175,810,850
COST OF OPERATIONS
Cost of refined products sold	51,689,474	48,415,627	125,316,249	151,604,774
Refinery operating expenses	3,153,646	2,953,528	9,468,409	8,420,650
Joint Marketing Agreement profit share	965,627	1,435,376	392,062	4,812,674
Pipeline operating expenses	91,969	63,099	266,454	170,582
Lease operating expenses	9,005	(1,143)	32,112	20,271
General and administrative expenses	891,210	312,365	1,503,533	1,058,267
Depletion, depreciation and amortization	504,719	414,837	1,415,519	1,217,005
Recovery of bad debt			(139,868)
Accretion expense	28,186	52,720	84,558	158,655
Total cost of operations	57,333,836	53,646,409	138,339,028	167,462,878
Income (loss) from operations	(2,645,530)	1,610,478	(10,095,986)	8,347,972
OTHER INCOME (EXPENSE)
Easement, interest and other income	157,840	724,349	415,700	856,816
Interest and other expense	(485,659)	(382,191)	(1,305,125)	(1,322,562)
Total other (expense)	(327,819)	342,158	(889,425)	(465,746)
Income (loss) before income taxes	(2,973,349)	1,952,636	(10,985,411)	7,882,226
Income tax benefit (expense)	1,034,798	(688,403)	3,735,040	(2,778,750)
Net income (loss)	$ (1,938,551)	$ 1,264,233	$ (7,250,371)	$ 5,103,476
Income (loss) per common share:
Basic	$ (0.19)	$ 0.12	$ (0.69)	$ 0.49
Diluted	$ (0.19)	$ 0.12	$ (0.69)	$ 0.49
Weighted average number of common shares outstanding:
Basic	10,464,715	10,453,802	10,460,849	10,451,168
Diluted	10,464,715	10,453,802	10,460,849	10,451,168

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
OPERATING ACTIVITIES
Net income (loss)	$ (7,250,371)	$ 5,103,476
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	1,415,519	1,217,005
Unrealized loss (gain) on derivatives	1,143,490	362,750
Deferred tax expense (benefit)	(3,735,040)	2,479,823
Amortization of debt issue costs	96,364	517,652
Accretion expense	84,558	158,655
Common stock issued for services	50,000	19,999
Recovery of bad debt	(139,868)
Changes in operating assets and liabilities
Accounts receivable	(1,815,584)	506,784
Prepaid expenses and other current assets	945,539	(274,435)
Deposits and other assets	570,444	(1,711,073)
Inventory	(1,011,662)	(2,420,176)
Accounts payable, accrued expenses and other liabilities	5,269,224	1,172,976
Accounts payable, related party	(300,000)	(1,174,168)
Net cash provided by (used in) operating activities	(4,677,387)	5,959,268
INVESTING ACTIVITIES
Capital expenditures	(11,255,725)	(8,156,298)
Change in restricted cash for investing activities	11,257,897	(13,021,438)
Net cash provide by (used in) investing activities	2,172	(21,177,736)
FINANCING ACTIVITIES
Proceeds from issuance of debt	6,898,931	28,000,000
Payments on long-term debt	(1,414,406)	(9,474,720)
Change in restricted cash for financing activities	(985,700)	(3,081,686)
Net cash provided by financing activities	4,498,825	15,443,594
Net increase (decrease) in cash and cash equivalents	(176,390)	225,126
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,677,485	1,518,359
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	2,601,709	1,743,997
Interest paid	1,827,794	959,665
Income taxes paid		$ 139,500

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1. Organization

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Nature of Operations. Blue Dolphin Energy Company (“Blue Dolphin,”) 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. (See “Note (4) Business Segment Information” for further discussion of our business segments.)

Structure and Management. Blue Dolphin was 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) Related Party Transactions,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Operating Agreement, and Jonathan Carroll.)

Our operations are conducted through the following active 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 (“BDPL”), a Delaware corporation.

● Blue Dolphin Petroleum Company, a Delaware corporation.

● Blue Dolphin Services Co., a Texas corporation.

See "Part I, Item 1. Business and Item 2. Properties” in our Form 10-K 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, principal facilities, and assets.

References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires.

Operating Risks. Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit 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 business and operational strategy will achieve anticipated outcomes.  Our operations, liquidity, and financial condition may be materially adversely affected if: (i) our strategy is not successful, (ii) our working capital requirements are not funded through Operations Payments by GEL TEX Marketing, LLC (“GEL”) under a Joint Marketing Agreement (the “Joint Marketing Agreement”), our profit share under the Joint Marketing Agreement, or certain advances from LEH, or (iii) we have future covenant violations under our loan agreements that are not waived.

For the three months ended September 30, 2016, we had a net loss of $1,938,551 compared to net income of $1,264,233 for the three months ended September 30, 2015. For the nine months ended September 30, 2016, we had a net loss of $7,250,371 compared to net income of $5,103,476 for the nine months ended September 30, 2015.

As of September 30, 2016, we had cash and cash equivalents and restricted cash (current portion) of $1,677,485 and $4,160,999, respectively. As of September 30, 2016, we had current assets of $22,404,232 and current liabilities (including the current portion of long-term debt) of $59,754,725, reflecting a working capital deficit of $37,350,493. Excluding the current portion of long-term debt, we had a working capital deficit of $5,229,711 as of September 30, 2016. Non-payment of Operations Payments to us by GEL under the Joint Marketing Agreement resulting from a contract-related dispute between the parties contributed to the working capital deficit as of September 30, 2016. (See “Note (19) Commitments and Contingencies – Genesis Agreements and Legal Matters” for a discussion related to Operations Payments and the Joint Marketing Agreement.)

As of December 31, 2015, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively. As of December 31, 2015, we had current assets of $19,629,841 and current liabilities (including the current portion of long-term debt) of $20,228,648, reflecting a working capital deficit of $598,807.

In addition to the Joint Marketing Agreement, 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.   An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contract-related dispute with Genesis.)

As of September 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank (“Sovereign”). As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.

Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (9) Long-Term Debt, Net” and “Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

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2. Basis of Presentation

9 Months Ended

Sep. 30, 2016

Accounting Policies [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 as of 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 and nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2016, or for any other period.

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3. Significant Accounting Policies

9 Months Ended

Sep. 30, 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 their 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 $1,677,485 and $1,853,875 as of September 30, 2016 and December 31, 2015, respectively.

Restricted Cash. As of September 30, 2016, total restricted cash was $8,519,580, comprised of restricted cash (current portion) totaling $4,160,999 and restricted cash, noncurrent totaling $4,358,581. As of December 31, 2015, total restricted cash was $18,791,777, comprised of restricted cash (current portion) totaling $3,175,299 and restricted cash, noncurrent totaling $15,616,478. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See “Note (9) Long-Term Debt, Net” for additional disclosures related to our 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 as of September 30, 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. 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” 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, commodity futures contracts may be used 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 hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements 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” 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 for any period presented.

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 and nine months ended September 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of 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” 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 Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of September 30, 2016 and December 31, 2015. We have determined the 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. Jet fuel, our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and 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 abandoning a segment of the pipeline assets. (See “Part I, Business – Governmental Regulation – Offshore Safety and Environmental Oversight – Decommissioning Requirements” in 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 three and nine month periods 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 a 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” 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” 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 directors, including the issuance of restricted common stock, 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” for additional disclosures related to treasury stock.)

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. For the three and nine months ended September 30, 2016, we adopted the following recently issued ASU’s:

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.

ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has 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. The following are recently issued, but not yet effective, ASU’s that may have an effect on our consolidated financial position, results of operations, or cash flows:

ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15. This guidance addresses eight specific cash flow issues in order to reduce future diversity of practice. For public business entities, the amendments in ASU 2016-15 are effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated statements of cash flows.

ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13. This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.

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 2015-11, 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 and the International Accounting Standards Board (the “IASB”) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the “Accounting Boards”) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the “TRG”). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASU’s as part of the TRG process include:

● August 2015 – 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).

● March 2016 – 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.

● April 2016 – ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU: (i) clarifies when promised goods or services are separately identifiable (i.e., distinct within the context of a contract), an important step in determining whether goods and services should be accounted for as separate performance obligations, (ii) allows entities to disregard goods or services that are immaterial in the context of a contract and provide an accounting policy election for accounting for certain shipping and handling activities, (iii) clarifies how an entity should evaluate the nature of its promise in granting a license of intellectual property, which will determine whether the entity recognizes revenue over time or at a point in time, and (iv) revises the guidance to address how entities should apply the exception for sales and usage-based royalties to licenses of intellectual property, recognize revenue for licenses that are not separate performance obligations, and evaluate different types of license restrictions (e.g., time-based, geography-based).

● May 2016 – ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update). Upon the adoption of ASU 2014-16, Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, and ASU 2014-09, several ASC guidance standards related to revenue recognition will be rescinded as no longer needed. These include ASC guidance standards for determining the nature of a host contract related to a hybrid financial instrument issued in the form of a share, revenue and expense recognition for freight services in process, accounting for shipping and handling fees and costs, accounting for consideration given by a vendor to a customer, and accounting for gas-balancing arrangements.

● May 2016 – ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients addresses issues such as collectability, contract modifications, completed contracts at transition, and noncash considerations as they relate to the new revenue recognition standard. 

We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and ASU 2016-12, 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 September 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.

Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation.

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4. Business Segment Information

9 Months Ended

Sep. 30, 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 periods indicated (and as of the dates indicated), was as follows:

	Three Months Ended September 30, 2016													Three Months Ended September 30, 2015
	Segment													Segment
	Refinery			Pipeline			Corporate &							Refinery			Pipeline			Corporate &
	Operations			Transportation			Other				Total			Operations			Transportation			Other				Total
Revenue from operations	$	54,668,780		$	19,526		$	-			$	54,688,306		$	55,210,962		$	45,925		$	-			$	55,256,887
Less: cost of operations(1)		(55,495,575	)		(129,160	)		(238,755	)			(55,863,490	)		(51,444,705	)		(114,675	)		(236,816	)			(51,796,196	)
Other non-interest income(2)		-			156,396			-				156,396			-			62,500			660,000				722,500
Adjusted EBITDA(3)		(826,795	)		46,762			(238,755	)			(1,018,788	)		3,766,257			(6,250	)		423,184				4,183,191
Less: JMA Profit Share(4)		(965,627	)		-			-				(965,627	)		(1,435,376	)		-			-				(1,435,376	)
EBITDA(3)	$	(1,792,422	)	$	46,762		$	(238,755	)					$	2,330,881		$	(6,250	)	$	423,184
Depletion, depreciation and amortization									(504,719	)												(414,837	)
Interest expense, net												(484,215	)												(380,342	)
Income (loss) before income taxes												(2,973,349	)												1,952,636
Income tax benefit (expense)												1,034,798													(688,403	)
Net income (loss)											$	(1,938,551	)											$	1,264,233
Capital expenditures(5)	$	4,182,747		$	-		$	-			$	4,182,747		$	2,355,811		$	-		$	-			$	2,355,811
Identifiable assets(6)	$	85,585,499		$	3,106,327		$	7,710,337			$	96,402,163		$	78,145,626		$	3,303,803		$	3,405,977			$	84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Nine Months Ended September 30, 2016													Nine Months Ended September 30, 2015
	Segment												Segment
	Refinery			Pipeline			Corporate &							Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total				Operations			Transportation			Other			Total
Revenue from operations	$	128,171,177		$	71,865		$	-		$	128,243,042			$	175,690,968		$	119,882		$	-		$	175,810,850
Less: cost of operations(1)		(135,452,537	)		(383,124	)		(695,786	)		(136,531,447	)			(160,208,576	)		(296,291	)		(928,331	)		(161,433,198	)
Other non-interest income(2)		-			412,061			-			412,061				-			187,500			660,000			847,500
Adjusted EBITDA(3)		(7,281,360	)		100,802			(695,786	)		(7,876,344	)			15,482,392			11,091			(268,331	)		15,225,152
Less: JMA Profit Share(4)		(392,062	)		-			-			(392,062	)			(4,812,674	)		-			-			(4,812,674	)
EBITDA(3)	$	(7,673,422	)	$	100,802		$	(695,786	)					$	10,669,718		$	11,091		$	(268,331	)
Depletion, depreciation and
amortization											(1,415,519	)												(1,217,005	)
Interest expense, net											(1,301,486	)												(1,313,247	)
Income (loss) before income taxes											(10,985,411	)												7,882,226
Income tax benefit (expense)											3,735,040													(2,778,750	)
Net income (loss)										$	(7,250,371	)											$	5,103,476
Capital expenditures(5)	$	11,255,725		$	-		$	-		$	11,255,725			$	8,156,298		$	-		$	-		$	8,156,298
Identifiable assets(6)	$	85,585,499		$	3,106,327		$	7,710,337		$	96,402,163			$	78,145,626		$	3,303,803		$	3,405,977		$	84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

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5. Prepaid Expenses and Other Current Assets

9 Months Ended

Sep. 30, 2016

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

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets as of the dates indicated consisted of the following:

	September 30,		December 31,
	2016		2015
Prepaid insurance	$	192,351	$	315,120
Prepaid listing fees		3,750		-
Prepaid related party operating expenses		-		624,570
	$	196,101	$	939,690

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6. Inventory

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,		December 31,
	2016		2015
HOBM	$	4,069,203	$	5,007,576
Jet fuel		3,744,702		2,045,784
Naphtha		417,223		309,850
AGO		280,277		278,278
Chemicals		261,518		122,777
Propane		24,860		17,860
Crude oil and condensate		19,041		19,041
LPM mix		3,156		7,152
	$	8,819,980	$	7,808,318

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7. Property, Plant and Equipment, Net

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net

Property, plant and equipment, net, as of the dates indicated consisted of the following:

	September 30,			December 31,
	2016			2015
Refinery and facilities	$	50,516,486		$	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
		54,224,861			43,896,303
Less: Accumulated depletion, depreciation, and amortization		(7,649,077	)		(6,234,161	)
		46,575,784			37,662,142
Construction in progress		14,707,943			11,179,670
	$	61,283,727		$	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 depreciated over the asset’s useful life. Interest cost capitalized was $1,776,863 and $556,032 as of September 30, 2016 and December 31, 2015, respectively.

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8. Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Accounts Payable, Related Party

We are party to several agreements with related parties. We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. A summary of these agreements follows:

LEH. We are party to an Operating Agreement, a Product Sales Agreement, a Terminal Services Agreement, a Loan and Security Agreement, and a Promissory Note with LEH. 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.

Operating Agreement. LEH manages and operates all of our properties pursuant to the Operating Agreement. 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 under the Operating Agreement, 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 either reflected within prepaid expenses and other current assets or accounts payable, related party in our consolidated balance sheets. (See “Note (5) Prepaid Expenses and Other Current Assets” for additional disclosures with respect to prepaid related party operating expenses.)

● Fees – For management and operation of the Nixon Facility, LEH receives: (i) weekly payments from GEL to cover direct expenses incurred in an amount not to exceed $750,000 per month (the “Operations Payments”), (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 to LEH are reflected within refinery operating expenses in our consolidated statements of operations. Fees owed to LEH under the Operating Agreement are reflected within accounts payable, related party in our consolidated balance sheets.

Product Sales Agreement. Under a Product Sales Agreement, LEH purchases jet fuel from the Nixon Facility for resale to third parties. Sales to LEH under the Product Sales Agreement are reflected within refined petroleum product sales in our consolidated statements of operations.

Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leases a petroleum storage tank at the Nixon Facility. The Terminal Services Agreement has an initial term of 12 months and automatically renews for additional terms of 6 months. The parties may terminate the Terminal Services Agreement upon 45 days’ written notice. Rental fees received from LEH under the Terminal Services Agreement are reflected within tank rental revenue in our consolidated statements of operations.

Loan and Security Agreement. In August 2016, BDPL entered into a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “LEH Loan Agreement”). The LEH Loan Agreement matures in August 2018, and accrues interest at rate of 16.00%. Under the LEH Loan Agreement, BDPL will make payments of $500,000 per year from the annual payment received from FLNG pursuant to a Master Easement Agreement between BDPL and FLNG dated December 11, 2013. A final balloon payment is due at maturity.

The proceeds of the LEH Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the LEH Loan Agreement. The LEH Loan Agreement is secured by: (i) the assignment of payments received by BDPL from FLNG under the Master Easement Agreement and (ii) certain real estate assets of BDPL. Outstanding principal and interest less associated debt issue costs owed to LEH under the LEH Loan Agreement are reflected in long-term debt, related party, current portion and long-term debt, related party, net of current portion in our consolidated balance sheets.

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with LEH in the original principal amount of $1,797,172 (the “LEH Note”). The LEH Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to LEH under the LEH Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

Ingleside Crude, LLC (“Ingleside”). We are party to an Amended and Restated Tank Lease Agreement and a Promissory Note with Ingleside. Ingleside is a related party of LEH and Jonathan Carroll.

Amended and Restated Tank Lease Agreement. Pursuant to an Amended and Restated Tank Lease Agreement with Ingleside, we lease petroleum storage tanks to meet periodic, additional storage needs. The Amended and Restated Tank Lease Agreement had an initial term of 30 days with automatic 30day renewal periods. The parties may terminate the tank lease agreement upon 30 days’ written notice. Renatal fees owed to Ingleside under the tank lease agreement are reflected within accounts payable, related party in our consolidated balance sheets. Amounts expensed as rental fees to Ingleside under the Amended and Restated Tank Lease Agreement are reflected within refinery operating expenses in our consolidated statements of operations.

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with Ingleside in the original principal amount of $679,385 (the “Ingleside Note”). The Ingleside Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to Ingleside under the Ingleside Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

Jonathan Carroll. We are party to Guaranty Fee Agreements and a Promissory Note with Jonathan Carroll. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin.

Guaranty Fee Agreements. Pursuant to Guaranty Fee Agreements, Jonathan Carroll receives fees for providing his personal guarantee on certain of our long-term debt. Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under certain loan agreements. Amounts owed to Jonathan Carroll under Guaranty Fee Agreements are reflected within accounts payable, related party in our consolidated balance sheets. (See “Note (9) Long-Term Debt, Net” for further discussion related to the Guaranty Fee Agreements.)

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with Jonathan Carroll in the original principal amount of $422,374 (the “Carroll Note”). The Carroll Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Carroll Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to Jonathan Carroll under the Carroll Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

As of September 30, 2016, accounts receivable related to LEH totaled $2,869,805.

Unsettled reimbursements associated with the Operating Agreement and reflected within prepaid expenses and other current assets as of the dates indicated were as follows:

	September 30,		December 31,
	2016		2015
LEH	$	-	$	624,570
	$	-	$	624,570

Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows:

	September 30,			December 31,
	2016			2015
LEH	$	5,797,172		$	-
Ingleside		679,385
Jonathan Carroll		422,374
		6,898,931			-
Less: Long-term debt,
related party,
current portion		(500,000	)		-
	$	6,398,931		$	-

Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows:

	September 30,			December 31,
	2016			2015
LEH	$	80,000		$	-
		80,000			-
Less: Interest payable,
current portion		(80,000	)		-
	$	-		$	-

Accounts payable, related party associated with the Amended and Restated Tank Lease Agreement as of the dates indicated was as follows:

	September 30,		December 31,
	2016		2015
Ingleside	$	—	$	300,000
		—	$	300,000

Refinery operating expenses associated with the Operating Agreement and Amended and Restated Tank Lease Agreement for the periods indicated were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	Amount		Per bbl		Amount		Per bbl		Amount		Per bbl		Amount		Per bbl
LEH	$	3,028,646	$	2.66	$	2,953,528	$	2.66	$	8,618,409	$	2.84	$	8,420,650	$	2.73
Ingleside		125,000	$	0.11		-	$	0.00		850,000	$	0.28		-	$	0.00
	$	3,153,646	$	2.77	$	2,953,528	$	2.66	$	9,468,409	$	3.12	$	8,420,650	$	2.73

Revenue associated with the Product Sales Agreement and Terminal Services Agreement for the periods indicated was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Refined petroleum product sales
LEH	$	14,536,997	$	-	$	23,449,071	$	-
Other customers		39,414,296		54,924,070		103,097,645		174,830,292
Total refined petroleum product sales		53,951,293		54,924,070		126,546,716		174,830,292
Tank rental revenue
LEH		426,000		-		750,000		-
Other customers		291,487		286,892		874,461		860,676
Total tank rental revenue		717,487		286,892		1,624,461		860,676
Pipeline operations
Other customers		19,526		45,925		71,865		119,882
Total revenue from operations	$	54,688,306	$	55,256,887	$	128,243,042	$	175,810,850

As of September 30, 2016, accounts receivable related to LEH totaled $2,869,805.

Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Jonathan Carroll	$	172,300	$	165,008	$	522,931	$	165,008
LEH		80,000		-		80,000		-
	$	252,300	$	165,008	$	602,931	$	165,008

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9. Long-Term Debt, Net

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt, Net

 Effective January 1, 2016, we adopted the provisions of the FASB ASC guidance that requires debt issue costs to be presented as an offset to their related debt. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported debt issue costs as a direct deduction of long-term debt.

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

	September 30, 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	$	24,111,986	$	(1,557,748	)	$	22,554,238		$	24,643,081	$	(1,623,810	)	$	23,019,271
Second Term Loan Due 2034		9,797,549		(737,370	)		9,060,179			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		369,987		-			369,987			924,969		-			924,969
Capital Leases		178,741		-			178,741			304,618		-			304,618
	$	35,758,263	$	(2,295,118	)	$	33,463,145		$	37,172,668	$	(2,391,482	)	$	34,781,186
Less: Long-term debt less
unamortized debt issue
costs, current portion							(32,120,782	)							(1,934,932	)
						$	1,342,363							$	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) as of the dates indicated consisted of the following:

	September 30,			December 31,
	2016			2015
Notre Dame Debt	$	1,638,952		$	1,482,801
LEH Loan Agreement		80,000			-
Second Term Loan Due 2034		43,836			39,193
First Term Loan Due 2034		33,030			34,883
Capital Leases		1,531			2,612
Term Loan Due 2017		309			4,779
		1,797,658			1,564,268
Less: Interest payable, current portion		(158,706	)		(81,467	)
	$	1,638,952		$	1,482,801

(See “Note (8) Related Party Transactions” for disclosures related to related party long-term debt.)

First Term Loan Due 2034. In June 2015, LE entered into a loan agreement and related security agreement with Sovereign as administrative agent and lender, providing for 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 a current monthly payment of principal and interest of $188,416, 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 (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As of September 30, 2016, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the First Term Loan Due 2034. As a result of these covenant defaults, Sovereign could declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with the loan was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the First Term Loan Due 2034 and financial covenant violations.)

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 September 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $121,048 and $142,002, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the First Term Loan Due 2034 totaled $365,420 and $142,002, 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) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. 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. In December 2015, LRM entered into a loan agreement and related security agreement with Sovereign as administrative agent and lender, providing for 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 a current monthly payment 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 (current portion) and restricted cash, noncurrent in our consolidated balance sheets.

As of September 30, 2016, LRM was in violation of the debt service coverage ratio, the current ratio, and the debt to net worth ratio financial covenants related to the Second Term Loan Due 2034. As a result of these covenant defaults, Sovereign could declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Accordingly, $8,775,050 in principal and interest under the Second Term Loan Due 2034 were classified within the current portion of long-term debt on our consolidated balance sheets. By letter dated November 10, 2016, Sovereign waived the financial covenant defaults as of the quarter ended June 30, 2016. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.)

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 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 September 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $49,094 and $0, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the Second Term Loan Due 2034 totaled $148,261 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) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.)

A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from 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 certain specified tanks, with respect to which Sovereign has 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.

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 Term Loan Due 2017 has a current monthly principal payment of $61,665 plus interest. Due to its maturity date, the Term Loan Due 2017 was classified within the current portion of long-term debt on our consolidated balance sheet as of September 30, 2016.

As of September 30, 2016, LRM was in violation of the debt service coverage ratio financial covenant related to the Term Loan Due 2017. As a result of this covenant default, Sovereign could declare the amounts owed under the Term Loan Due 2017 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. The Term Loan Due 2017 was already classified within the current portion of longterm debt on our consolidated balance sheets due to the loan’s shortterm maturity date. Sovereign waived the financial covenant default as of the quarter ended September 30, 2016. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (1) Organization – Operating Risks” and “Note (20) Subsequent Events” for additional disclosures related to the Second Term Loan Due 2034 and financial covenant violations.)

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 September 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $2,158 and $6,506, respectively. For the nine months ended September 30, 2016 and 2015, guaranty fees related to the Term Loan Due 2017 totaled $9,250 and $6,506, 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) Related Party Transactions” 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 as of the dates indicated follows:

	September 30,		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

9 Months Ended

Sep. 30, 2016

Disclosure Text Block Supplement [Abstract]

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities as of the dates indicated consisted of the following: 

	September 30,		December 31,
	2016		2015
Unrealized hedging loss	$	1,326,890	$	183,400
Unearned revenue		597,162		781,859
Customer deposits		450,000		-
Genesis JMA Profit Share payable		245,255		388,364
Other payable		166,314		157,714
Board of director fees payable		133,929		86,429
Property taxes		92,678		-
Transportation and inspection		38,000		-
Excise and income taxes payable		12,852		1,290,101
Insurance		-		103,024
	$	3,063,080	$	2,990,891

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11. Asset Retirement Obligations

9 Months Ended

Sep. 30, 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 depreciate 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:

	September 30,			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		(61,408	)		(92,330	)
Accretion expense		84,558			211,375
		2,009,014			1,985,864
Less: asset retirement obligations, current portion		(25,972	)		(38,644	)
Long-term asset retirement obligations, at the end of the period	$	1,983,042		$	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. As of September 30, 2016 and December 31, 2015, we recognized $61,408 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 September 30, 2016 and 2015, we recognized $0 in abandonment expense. For the nine months ended September 30, 2016 and 2015, we recognized $0 in abandonment expense.

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12. Treasury Stock

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Treasury Stock

As of September 30, 2016 and December 31, 2015, we had 150,000 shares of treasury stock.

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13. Concentration of Risk

9 Months Ended

Sep. 30, 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. As of September 30, 2016 and December 31, 2015, we had cash balances in excess of the FDIC insurance limit per depositor in the amount of $9,345,560 and $19,594,883, respectively.

Key Supplier. Under a Crude Oil and Supply Throughput Services Agreement dated in August 2011 (the “Crude Supply Agreement”), GEL supplies crude oil and condensate to the Nixon Facility. The initial term of the Crude Supply Agreement 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., another Genesis affiliate (“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.

(See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Crude Supply Agreement and a discussion of the current contract-related dispute with Genesis.)

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 September 30, 2016, we had 4 customers that accounted for approximately 70% of our refined petroleum products sales. These 4 customers represented approximately $6.7 million in accounts receivable as of September 30, 2016. For the three months ended September 30, 2015, we had 5 customers that accounted for approximately 81% of our refined petroleum products sales. These 5 customers represented approximately $5.7 million in accounts receivable as of September 30, 2015.

For the nine months ended September 30, 2016, we had 4 customers that accounted for approximately 64% of our refined petroleum products sales. These 4 customers represented approximately $5.5 million in accounts receivable as of September 30, 2016. For the nine months ended September 30, 2015, we had 3 customers that accounted for approximately 55% of our refined petroleum products sales. These 3 customers represented approximately $4.4 million in accounts receivable as of September 30, 2015.

For the three months ended September 30, 2016, 1 of our 4 significant customers was LEH, a related party. LEH accounted for approximately 27% of our refined petroleum product sales. For the nine months ended September 30, 2016, LEH accounted for approximately 19% of our refined petroleum product sales. As of September 30, 2016, LEH represented approximately $2.9 million in accounts receivable. LEH was not a customer during 2015. (See “Note (8) Related Party Transactions” for additional disclosures with respect to related parties.)

Refined Petroleum Product Sales. Our refined petroleum products are primarily sold in the U.S. However, with the opening of the Mexican diesel market to private companies, we began exporting low sulfur diesel to Mexico during the second quarter of 2016. Total refined petroleum product sales by distillation (from light to heavy) for the periods indicated consisted of the following:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2016						2015						2016						2015
LPG mix	$	237,009			0.4	%	$	617,715			1.1	%	$	621,313			0.5	%	$	909,207			0.5	%
Naphtha		11,870,484			22.0	%		11,218,381			20.4	%		28,183,809			22.3	%		38,048,064			21.8	%
Jet fuel		15,104,900			28.0	%		17,782,534			32.4	%		41,150,686			32.5	%		51,713,507			29.6	%
HOBM		14,206,759			26.4	%		9,609,536			17.5	%		25,259,753			20.0	%		40,640,975			23.2	%
Reduced Crude			0.0	%		50,407			0.1	%		3,791,919			3.0	%		50,407			0.0	%
AGO		12,532,141			23.2	%		15,645,497			28.5	%		27,539,236			21.7	%		43,468,132			24.9	%
	$	53,951,293			100.0	%	$	54,924,070			100.0	%	$	126,546,716			100.0	%	$	174,830,292			100.0	%

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14. Leases

9 Months Ended

Sep. 30, 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 that expires in September 2017. The lease included a free rent period, has escalating rent payment provisions, and requires payment of a portion of operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended September 30, 2016 and 2015, rent expense totaled $33,251 and $29,857, respectively. For the nine months ended September 30, 2016 and 2015, rent expense totaled $92,966 and $112,746, respectively.

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15. Income Taxes

9 Months Ended

Sep. 30, 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 September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Current:
Federal	$	-	$	(37,620	)	$	-	$	(122,863	)
State		-		(36,102	)		-		(148,656	)
Deferred:
Federal		1,034,798		(614,681	)		3,735,040		(2,507,231	)
	$	1,034,798	$	(688,403	)	$	3,735,040	$	(2,778,750	)

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 basis, 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 for a period of 20 years 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 Change			Post-Ownership Change			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
Net operating losses		-			4,230,763			4,230,763
Balance at June 30, 2016		9,614,449			19,719,054			29,333,503
Net operating losses		-			2,487,642			2,487,642
Balance at September 30, 2016	$	9,614,449		$	22,206,696		$	31,821,145

Deferred Tax Assets and Liabilities. As of September 30, 2016 and December 31, 2015, approximately $7.3 million and $3.6 million, respectively, of net deferred tax assets remained available for future use. Significant components of deferred tax assets and liabilities as of the dates indicated were as follow:

	September 30,			December 31,
	2016			2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	13,089,512		$	8,815,794
Start-up costs (Nixon Facility)		1,407,697			1,510,699
Asset retirement obligations liability/deferred revenue		714,961			717,723
Unrealized hedges		451,141			62,356
AMT credit and other		257,323			302,086
Total deferred tax assets		15,920,634			11,408,658
Deferred tax liabilities:
Fair market value adjustments		(46,116	)		(46,116	)
Unrealized hedges		-			-
Basis differences in property and equipment		(6,261,919	)		(5,484,983	)
Total deferred tax liabilities		(6,308,035	)		(5,531,099	)
		9,612,599			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
Deferred tax assets, net	$	7,342,277		$	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 September 30, 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 $7.3 million and $3.6 million, respectively, were realizable, and as a result, reflected a valuation allowance of $2.3 million at each date.

Current Versus Long-Term. Effective April 1, 2016, we adopted the provisions of the FASB ASC guidance that simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net.

Uncertain Tax Positions. We 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 and nine months ended September 30, 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

9 Months Ended

Sep. 30, 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 September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Net income (loss)	$           (1,938,551)	$            1,264,233	$           (7,250,371)	$            5,103,476
Basic and diluted income per share	$                    (0.19)	$                     0.12	$                    (0.69)	$                     0.49
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,464,715	10,453,802	10,460,849	10,451,168

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 and nine months ended September 30, 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

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurement

The purchase and sale of financial instruments may be executed for the purpose of economically hedging commodity price risks associated with our refined petroleum products and the purchase of crude oil and condensate. When executed these financial instruments are direct contractual obligations of our crude supplier and not us. However, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments. 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 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 as of September 30, 2016 and December 31, 2015 due to their short-term maturities. The fair value of our long-term debt, net including the current portion as of September 30, 2016 and December 31, 2015 was $39,758,263 and $37,172,668, 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 September 30, 2016 and December 31, 2015 and the basis for the measurement:

		Fair Value Measurement at September 30, 2016 Using
Financial assets (liabilities):	Carrying Value at September 30, 2016	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$                   (1,326,890)	$         (1,326,890)	$                     -	$                      -
		Fair Value Measurement at December 31, 215 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$                      (183,400)	$            (183,400)	$                     -	$                      -

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

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18. Inventory Risk Management

9 Months Ended

Sep. 30, 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, commodity futures contracts may be used 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 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 to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. 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.

As of September 30, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered into as economic hedges. 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	290,000	-	-

The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets as of September 30, 2016 and December 31, 2015:

		Fair Value
Asset Derivatives	Balance Sheets Location	September 30, 2016	December 31, 2015
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$        (1,326,890)	$      (183,400)

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended September 30,		Nine Months Ended September 30,
Derivatives	Statements of Operations Location	2016	2015	2016	2015
Commodity contracts	Cost of refined products sold	$                770,838	$                  2,205,291	$        (2,588,734)	$           1,762,582

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19. Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Operating Agreement. (See “Note (8) Related Party Transactions” for additional disclosures related to the Operating Agreement.)

Genesis Agreements. Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows:

Crude Supply Agreement. Under the Crude Supply Agreement, GEL supplies crude oil and condensate to the Nixon Facility. GEL supplies crude oil and condensate to us at cost plus freight expense and any costs associated with 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 within this section. 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 certain output produced at the Nixon Facility and share the associated Gross Profits (as defined below) from such sales. Payments for the sale of certain output produced at the Nixon Facility are made directly to GEL as collection agent, and associated customers must satisfy GEL’s customer credit approval process. The Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of certain output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement). Key provisions of the Joint Marketing Agreement 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. In addition, we are entitled to receive reimbursement for accounting fees, if incurred, not to exceed $50,000 per month. We assigned our rights to the Operations 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 is entitled to receive 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share, and we are entitled to receive 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for a calendar month is payable to GEL and us in the following manner: (i) GEL is entitled to receive 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we are entitled to receive 80% of the remaining Gross Profits over the Threshold Amount as our Profit Share. The GEL Profit Share plus the Performance Fee are collectively referred to as the “Joint Marketing Agreement Profit Share” or the “JMA Profit Share”.

The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. 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, as lender and lienholder pursuant to the First Term Loan Due 2034. (See “Note (9) Long-Term Debt, Net” for further discussion related to the First Term Loan Due 2034.)

Genesis Contract-Related Dispute. LE currently has a contract-related dispute with GEL related to the Joint Marketing Agreement and Crude Supply Agreement.  (See “Legal Matters” below for a discussion of the current contract-related dispute with Genesis.)

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 August 2015, we received a letter from the Bureau of Ocean Energy Management (the “BOEM”) requiring additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. In July 2016, the BOEM issued Notice to Lessees (“NTL”) No. 2016-N01 (Requiring Additional Security), which changes the way that lessees and rights-of-way holders demonstrate financial strength and reliability to plug and abandon wells, as well as decommission and remove platforms and pipelines at the end of production or service activities. The NTL, which changed an earlier supplemental waiver process to a self-insurance model, became effective in September 2016. Pursuant to the NTL, the BOEM requested that lessees submit any relevant information needed for an overall financial review of the lessees account. The BOEM indicated that it would use this information to evaluate a lessees’ ability to carry out its obligations and determine whether, and/or how much self-insurance a lessee can use.

In October 2016, we received a letter from the BOEM summarizing the amount required as additional security on our existing pipeline rights-of-way. The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental pipeline bonds or acceptable financial reassurance of approximately $4.6 million. As of September 30, 2016 and December 31, 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. Of the 5 rights-of-ways reflected in the BOEM’s October 2016 letter, one right-of-way was abandoned-in-place in May 1997. We requested permits from the Bureau of Safety and Environmental Enforcement (the “BSEE”) to decommission and abandon-in-place 3 of the rights-of-way in April 2016, one of which also requires approval from the U.S. Army Corps of Engineers. 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. If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.

Financing Agreements. (See “Note (9) Long-Term Debt, Net” 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.

Genesis Contract-Related Dispute. As described above under “Genesis Agreements,” we are party to a variety of contracts and agreements with Genesis and its affiliates, including GEL that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services.

In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the “Petition”) against LE and LEH. The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, in connection with an agreement by LEH to supply jet fuel acquired from LE to a customer. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GEL’s claims in the Petition are without merit and intends to defend the matter vigorously.

In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of a Dispute Resolution Agreement between the parties (the “Arbitration”). The Arbitration alleges that GEL breached the Crude Supply Agreement related to:

(i)	failure to provide crude oil and condensate at cost as defined in the Crude Supply Agreement, and
(ii)	significant under delivery of crude oil and condensate, resulting in significant refinery downtime and a significant decrease in refinery throughput, refinery production, and refined petroleum product sales for the nine months ended September 30, 2016.

With regard to the Petition, a trial date has been set for December 5, 2016, although the parties may elect arbitration prior to that date. With respect to the Arbitration, an initial hearing was held on November 9, 2016 at which the parties presented evidence supporting their position. The next hearing date related to Arbitration is November 16, 2016.

We do not expect the temporary injunction issued by the court related to the Litigation to have a material effect on our results of operations or financial condition. However, although GEL resumed normal delivery of crude oil and condensate to the Nixon Facility in July 2016, the adverse change in our relationship with Genesis has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has disrupted our normal business operations and diverted management’s focus away from operations. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet as of September 30, 2016.

Other Legal Matters. From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

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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20. Subsequent Events

9 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

Financial Covenant Defaults. As of September 30, 2016, LE and LRM were in violation of certain financial covenants related to the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017. As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.

By letter dated November 10, 2016, Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations.

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3. Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 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 $1,677,485 and $1,853,875 as of September 30, 2016 and December 31, 2015, respectively.

Restricted Cash

Restricted Cash. As of September 30, 2016, total restricted cash was $8,519,580, comprised of restricted cash (current portion) totaling $4,160,999 and restricted cash, noncurrent totaling $4,358,581. As of December 31, 2015, total restricted cash was $18,791,777, comprised of restricted cash (current portion) totaling $3,175,299 and restricted cash, noncurrent totaling $15,616,478. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See “Note (9) Long-Term Debt, Net” for additional disclosures related to our 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 as of September 30, 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. 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” 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, commodity futures contracts may be used 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 hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements 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” 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 for any period presented.

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 and nine months ended September 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of 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” 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 Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of September 30, 2016 and December 31, 2015. We have determined the 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. Jet fuel, our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and 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 abandoning a segment of the pipeline assets. (See “Part I, Business – Governmental Regulation – Offshore Safety and Environmental Oversight – Decommissioning Requirements” in 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 three and nine month periods 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 a 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” 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” 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 directors, including the issuance of restricted common stock, 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” for additional disclosures related to treasury stock.)

New Pronouncements Adopted

New Pronouncements Adopted. The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. For the three and nine months ended September 30, 2016, we adopted the following recently issued ASU’s:

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.

ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has 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. The following are recently issued, but not yet effective, ASU’s that may have an effect on our consolidated financial position, results of operations, or cash flows:

ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15. This guidance addresses eight specific cash flow issues in order to reduce future diversity of practice. For public business entities, the amendments in ASU 2016-15 are effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated statements of cash flows.

ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13. This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.

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 2015-11, 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 and the International Accounting Standards Board (the “IASB”) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the “Accounting Boards”) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the “TRG”). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASU’s as part of the TRG process include:

● August 2015 – 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).

● March 2016 – 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.

● April 2016 – ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU: (i) clarifies when promised goods or services are separately identifiable (i.e., distinct within the context of a contract), an important step in determining whether goods and services should be accounted for as separate performance obligations, (ii) allows entities to disregard goods or services that are immaterial in the context of a contract and provide an accounting policy election for accounting for certain shipping and handling activities, (iii) clarifies how an entity should evaluate the nature of its promise in granting a license of intellectual property, which will determine whether the entity recognizes revenue over time or at a point in time, and (iv) revises the guidance to address how entities should apply the exception for sales and usage-based royalties to licenses of intellectual property, recognize revenue for licenses that are not separate performance obligations, and evaluate different types of license restrictions (e.g., time-based, geography-based).

● May 2016 – ASU 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting (SEC Update). Upon the adoption of ASU 2014-16, Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, and ASU 2014-09, several ASC guidance standards related to revenue recognition will be rescinded as no longer needed. These include ASC guidance standards for determining the nature of a host contract related to a hybrid financial instrument issued in the form of a share, revenue and expense recognition for freight services in process, accounting for shipping and handling fees and costs, accounting for consideration given by a vendor to a customer, and accounting for gas-balancing arrangements.

● May 2016 – ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients addresses issues such as collectability, contract modifications, completed contracts at transition, and noncash considerations as they relate to the new revenue recognition standard. 

We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and ASU 2016-12, 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 September 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.

Reclassification

Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation.

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4. Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Business segment reporting

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Three Months Ended September 30, 2016													Three Months Ended September 30, 2015
	Segment													Segment
	Refinery			Pipeline			Corporate &							Refinery			Pipeline			Corporate &
	Operations			Transportation			Other				Total			Operations			Transportation			Other				Total
Revenue from operations	$	54,668,780		$	19,526		$	-			$	54,688,306		$	55,210,962		$	45,925		$	-			$	55,256,887
Less: cost of operations(1)		(55,495,575	)		(129,160	)		(238,755	)			(55,863,490	)		(51,444,705	)		(114,675	)		(236,816	)			(51,796,196	)
Other non-interest income(2)		-			156,396			-				156,396			-			62,500			660,000				722,500
Adjusted EBITDA(3)		(826,795	)		46,762			(238,755	)			(1,018,788	)		3,766,257			(6,250	)		423,184				4,183,191
Less: JMA Profit Share(4)		(965,627	)		-			-				(965,627	)		(1,435,376	)		-			-				(1,435,376	)
EBITDA(3)	$	(1,792,422	)	$	46,762		$	(238,755	)					$	2,330,881		$	(6,250	)	$	423,184
Depletion, depreciation and amortization									(504,719	)												(414,837	)
Interest expense, net												(484,215	)												(380,342	)
Income (loss) before income taxes												(2,973,349	)												1,952,636
Income tax benefit (expense)												1,034,798													(688,403	)
Net income (loss)											$	(1,938,551	)											$	1,264,233
Capital expenditures(5)	$	4,182,747		$	-		$	-			$	4,182,747		$	2,355,811		$	-		$	-			$	2,355,811
Identifiable assets(6)	$	85,585,499		$	3,106,327		$	7,710,337			$	96,402,163		$	78,145,626		$	3,303,803		$	3,405,977			$	84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

	Nine Months Ended September 30, 2016													Nine Months Ended September 30, 2015
	Segment												Segment
	Refinery			Pipeline			Corporate &							Refinery			Pipeline			Corporate &
	Operations			Transportation			Other			Total				Operations			Transportation			Other			Total
Revenue from operations	$	128,171,177		$	71,865		$	-		$	128,243,042			$	175,690,968		$	119,882		$	-		$	175,810,850
Less: cost of operations(1)		(135,452,537	)		(383,124	)		(695,786	)		(136,531,447	)			(160,208,576	)		(296,291	)		(928,331	)		(161,433,198	)
Other non-interest income(2)		-			412,061			-			412,061				-			187,500			660,000			847,500
Adjusted EBITDA(3)		(7,281,360	)		100,802			(695,786	)		(7,876,344	)			15,482,392			11,091			(268,331	)		15,225,152
Less: JMA Profit Share(4)		(392,062	)		-			-			(392,062	)			(4,812,674	)		-			-			(4,812,674	)
EBITDA(3)	$	(7,673,422	)	$	100,802		$	(695,786	)					$	10,669,718		$	11,091		$	(268,331	)
Depletion, depreciation and
amortization											(1,415,519	)												(1,217,005	)
Interest expense, net											(1,301,486	)												(1,313,247	)
Income (loss) before income taxes											(10,985,411	)												7,882,226
Income tax benefit (expense)											3,735,040													(2,778,750	)
Net income (loss)										$	(7,250,371	)											$	5,103,476
Capital expenditures(5)	$	11,255,725		$	-		$	-		$	11,255,725			$	8,156,298		$	-		$	-		$	8,156,298
Identifiable assets(6)	$	85,585,499		$	3,106,327		$	7,710,337		$	96,402,163			$	78,145,626		$	3,303,803		$	3,405,977		$	84,855,406

(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” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

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5. Prepaid Expenses and Other Current Assets (Tables)

9 Months Ended

Sep. 30, 2016

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

Prepaid balances

Prepaid expenses and other current assets as of the dates indicated consisted of the following:

	September 30,		December 31,
	2016		2015
Prepaid insurance	$	192,351	$	315,120
Prepaid listing fees		3,750		-
Prepaid related party operating expenses		-		624,570
	$	196,101	$	939,690

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6. Inventory (Tables)

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventory

Inventory as of the dates indicated consisted of the following:

	September 30,		December 31,
	2016		2015
HOBM	$	4,069,203	$	5,007,576
Jet fuel		3,744,702		2,045,784
Naphtha		417,223		309,850
AGO		280,277		278,278
Chemicals		261,518		122,777
Propane		24,860		17,860
Crude oil and condensate		19,041		19,041
LPM mix		3,156		7,152
	$	8,819,980	$	7,808,318

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

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Property and equipment

Property, plant and equipment, net, as of the dates indicated consisted of the following:

	September 30,			December 31,
	2016			2015
Refinery and facilities	$	50,516,486		$	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
		54,224,861			43,896,303
Less: Accumulated depletion, depreciation, and amortization		(7,649,077	)		(6,234,161	)
		46,575,784			37,662,142
Construction in progress		14,707,943			11,179,670
	$	61,283,727		$	48,841,812

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8. Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Accounts Payable, Related Party

Accounts payable, related party associated with the Amended and Restated Tank Lease Agreement as of the dates indicated was as follows:

	September 30,		December 31,
	2016		2015
Ingleside	$	—	$	300,000
		—	$	300,000

Prepaid operating expenses, related party

Unsettled reimbursements associated with the Operating Agreement and reflected within prepaid expenses and other current assets as of the dates indicated were as follows:

	September 30,		December 31,
	2016		2015
LEH	$	-	$	624,570
	$	-	$	624,570

Long-term debt, related party associated with the LEH Loan Agreement, LEH Note, Ingleside Note, and Carroll Note as of the dates indicated was as follows:

	September 30,			December 31,
	2016			2015
LEH	$	5,797,172		$	-
Ingleside		679,385
Jonathan Carroll		422,374
		6,898,931			-
Less: Long-term debt,
related party,
current portion		(500,000	)		-
	$	6,398,931		$	-

Accrued interest associated with the LEH Loan Agreement as of the dates indicated was as follows:

	September 30,			December 31,
	2016			2015
LEH	$	80,000		$	-
		80,000			-
Less: Interest payable,
current portion		(80,000	)		-
	$	-		$	-

Refinery operating expenses

Refinery operating expenses associated with the Operating Agreement and Amended and Restated Tank Lease Agreement for the periods indicated were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	Amount		Per bbl		Amount		Per bbl		Amount		Per bbl		Amount		Per bbl
LEH	$	3,028,646	$	2.66	$	2,953,528	$	2.66	$	8,618,409	$	2.84	$	8,420,650	$	2.73
Ingleside		125,000	$	0.11		-	$	0.00		850,000	$	0.28		-	$	0.00
	$	3,153,646	$	2.77	$	2,953,528	$	2.66	$	9,468,409	$	3.12	$	8,420,650	$	2.73

Product Sales Agreement

Revenue rassociated with the Product Sales Agreement and Terminal Services Agreement for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Refined petroleum product sales
LEH	$	14,536,997	$	-	$	23,449,071	$	-
Other customers		39,414,296		54,924,070		103,097,645		174,830,292
Total refined petroleum product sales		53,951,293		54,924,070		126,546,716		174,830,292
Tank rental revenue
LEH		426,000		-		750,000		-
Other customers		291,487		286,892		874,461		860,676
Total tank rental revenue		717,487		286,892		1,624,461		860,676
Pipeline operations
Other customers		19,526		45,925		71,865		119,882
Total revenue from operations	$	54,688,306	$	55,256,887	$	128,243,042	$	175,810,850

Interest Expenses

Interest expense associated with the LEH Loan Agreement and Guaranty Fee Agreements for the periods indicated were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Jonathan Carroll	$	172,300	$	165,008	$	522,931	$	165,008
LEH		80,000		-		80,000		-
	$	252,300	$	165,008	$	602,931	$	165,008

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9. Long-Term Debt, Net (Tables)

9 Months Ended

Sep. 30, 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, as of the dates indicated consisted of the following:

	September 30, 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	$	24,111,986	$	(1,557,748	)	$	22,554,238		$	24,643,081	$	(1,623,810	)	$	23,019,271
Second Term Loan Due 2034		9,797,549		(737,370	)		9,060,179			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		369,987		-			369,987			924,969		-			924,969
Capital Leases		178,741		-			178,741			304,618		-			304,618
	$	35,758,263	$	(2,295,118	)	$	33,463,145		$	37,172,668	$	(2,391,482	)	$	34,781,186
Less: Long-term debt less
unamortized debt issue
costs, current portion							(32,120,782	)							(1,934,932	)
						$	1,342,363							$	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) as of the dates indicated consisted of the following:

	September 30,			December 31,
	2016			2015
Notre Dame Debt	$	1,638,952		$	1,482,801
LEH Loan Agreement		80,000			-
Second Term Loan Due 2034		43,836			39,193
First Term Loan Due 2034		33,030			34,883
Capital Leases		1,531			2,612
Term Loan Due 2017		309			4,779
		1,797,658			1,564,268
Less: Interest payable, current portion		(158,706	)		(81,467	)
	$	1,638,952		$	1,482,801

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

A summary of equipment held under long-term capital leases as of the dates indicated follows:

	September 30,		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)

9 Months Ended

Sep. 30, 2016

Disclosure Text Block Supplement [Abstract]

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities as of the dates indicated consisted of the following: 

	September 30,		December 31,
	2016		2015
Unrealized hedging loss	$	1,326,890	$	183,400
Unearned revenue		597,162		781,859
Customer deposits		450,000		-
Genesis JMA Profit Share payable		245,255		388,364
Other payable		166,314		157,714
Board of director fees payable		133,929		86,429
Property taxes		92,678		-
Transportation and inspection		38,000		-
Excise and income taxes payable		12,852		1,290,101
Insurance		-		103,024
	$	3,063,080	$	2,990,891

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11. Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

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

	September 30,			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		(61,408	)		(92,330	)
Accretion expense		84,558			211,375
		2,009,014			1,985,864
Less: asset retirement obligations, current portion		(25,972	)		(38,644	)
Long-term asset retirement obligations, at the end of the period	$	1,983,042		$	1,947,220

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13. Concentration of Risk (Tables)

9 Months Ended

Sep. 30, 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 September 30,												Nine Months Ended September 30,
	2016						2015						2016						2015
LPG mix	$	237,009			0.4	%	$	617,715			1.1	%	$	621,313			0.5	%	$	909,207			0.5	%
Naphtha		11,870,484			22.0	%		11,218,381			20.4	%		28,183,809			22.3	%		38,048,064			21.8	%
Jet fuel		15,104,900			28.0	%		17,782,534			32.4	%		41,150,686			32.5	%		51,713,507			29.6	%
HOBM		14,206,759			26.4	%		9,609,536			17.5	%		25,259,753			20.0	%		40,640,975			23.2	%
Reduced Crude			0.0	%		50,407			0.1	%		3,791,919			3.0	%		50,407			0.0	%
AGO		12,532,141			23.2	%		15,645,497			28.5	%		27,539,236			21.7	%		43,468,132			24.9	%
	$	53,951,293			100.0	%	$	54,924,070			100.0	%	$	126,546,716			100.0	%	$	174,830,292			100.0	%

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15. Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income tax benefit (expense)

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Current:
Federal	$	-	$	(37,620	)	$	-	$	(122,863	)
State		-		(36,102	)		-		(148,656	)
Deferred:
Federal		1,034,798		(614,681	)		3,735,040		(2,507,231	)
	$	1,034,798	$	(688,403	)	$	3,735,040	$	(2,778,750	)

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 Change			Post-Ownership Change			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
Net operating losses		-			4,230,763			4,230,763
Balance at June 30, 2016		9,614,449			19,719,054			29,333,503
Net operating losses		-			2,487,642			2,487,642
Balance at September 30, 2016	$	9,614,449		$	22,206,696		$	31,821,145

Deferred tax assets and deferred tax liabilities

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

	September 30,			December 31,
	2016			2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$	13,089,512		$	8,815,794
Start-up costs (Nixon Facility)		1,407,697			1,510,699
Asset retirement obligations liability/deferred revenue		714,961			717,723
Unrealized hedges		451,141			62,356
AMT credit and other		257,323			302,086
Total deferred tax assets		15,920,634			11,408,658
Deferred tax liabilities:
Fair market value adjustments		(46,116	)		(46,116	)
Unrealized hedges		-			-
Basis differences in property and equipment		(6,261,919	)		(5,484,983	)
Total deferred tax liabilities		(6,308,035	)		(5,531,099	)
		9,612,599			5,877,559
Valuation allowance		(2,270,322	)		(2,270,322	)
Deferred tax assets, net	$	7,342,277		$	3,607,237

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16. Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 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 September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Net income (loss)	$           (1,938,551)	$            1,264,233	$           (7,250,371)	$            5,103,476
Basic and diluted income per share	$                    (0.19)	$                     0.12	$                    (0.69)	$                     0.49
Basic and Diluted
Weighted average number of shares of
common stock outstanding and potential
dilutive shares of common stock	10,464,715	10,453,802	10,460,849	10,451,168

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17. Fair Value Measurement (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2016 and December 31, 2015 and the basis for the measurement:

		Fair Value Measurement at September 30, 2016 Using
Financial assets (liabilities):	Carrying Value at September 30, 2016	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$                   (1,326,890)	$         (1,326,890)	$                     -	$                      -
		Fair Value Measurement at December 31, 215 Using
Financial assets (liabilities):	Carrying Value at December 31, 2015	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Commodity contracts	$                      (183,400)	$            (183,400)	$                     -	$                      -

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18. Inventory Risk Management (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Notional volume of outstanding contracts by type of instrument

As of September 30, 2016, we had the following obligations based on futures contracts of refined petroleum products and crude oil and condensate that were entered into as economic hedges. 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	290,000	-	-

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 as of September 30, 2016 and December 31, 2015: 

		Fair Value
Asset Derivatives	Balance Sheets Location	September 30, 2016	December 31, 2015
	Prepaid expenses and other current
	assets (accrued expenses and other
Commodity contracts	current liabilities)	$        (1,326,890)	$      (183,400)

Effect of derivative instruments

The following table provides the effect of derivative instruments in our consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015: 

		Gain (Loss) Recognized
		Three Months Ended September 30,		Nine Months Ended September 30,
Derivatives	Statements of Operations Location	2016	2015	2016	2015
Commodity contracts	Cost of refined products sold	$                770,838	$                  2,205,291	$        (2,588,734)	$           1,762,582

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1. Organization (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss)	$ (1,938,551)	$ 1,264,233	$ (7,250,371)	$ 5,103,476
Cash and cash equivalents	1,677,485	$ 1,518,359	1,677,485	$ 1,518,359	$ 1,853,875	$ 1,293,233
Restricted cash (current portion)	4,160,999		4,160,999		3,175,299
Current assets	22,404,232		22,404,232		19,629,841
Current liabilities	59,754,725		59,754,725		20,228,648
Working capital deficit current portion	$ 598,807		$ 598,807		$ 1,336,125

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3. Significant Accounting Policies (Details Narrative) - USD ($)	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 1,677,485	$ 1,853,875	$ 1,518,359	$ 1,293,233
Restricted cash	8,519,580	18,791,777
Restricted cash (current portion)	4,160,999	3,175,299
Restricted cash, noncurrent	4,358,581	15,616,478
Allowance for doubtful accounts	0	139,868
Trade name	$ 303,346	303,346
Deferred tax assets		3,500,000
Debt issue costs		$ 2,400,000

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4. Business Segment Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenue from operations	$ 54,688,306	$ 55,256,887	$ 128,243,042	$ 175,810,850
Income tax benefit (expense)	(1,034,798)	688,403	(3,735,040)	2,778,750
Net income (loss)	(1,938,551)	1,264,233	(7,250,371)	5,103,476
Refinery Operations [Member]
Revenue from operations	54,668,780	55,210,962	128,171,177	175,690,968
Less: cost of operations	(55,495,575)	(51,444,705)	(135,452,537)	(160,208,576)
Other non-interest income
Adjusted EBITDA	(826,795)	3,766,257	(7,281,360)	15,482,392
Less: JMA Profit Share	(965,627)	(1,435,376)	(392,062)	(4,812,674)
EBITDA	(1,792,422)	2,330,881	(7,673,422)	10,669,718
Capital expenditures	4,182,747	2,355,811		8,156,298
Identifiable assets	85,585,499	78,145,626		78,145,626
Pipeline Transportation [Member]
Revenue from operations	19,526	45,925	71,865	119,882
Less: cost of operations	(129,160)	(114,675)	(383,124)	(296,291)
Other non-interest income	156,396	62,500	412,061	187,500
Adjusted EBITDA	46,762	(6,250)	100,802	11,091
Less: JMA Profit Share
EBITDA	46,762	(6,250)	100,802	11,091
Capital expenditures
Identifiable assets	3,106,327	3,303,803		3,303,803
Corporate and Other [Member]
Revenue from operations
Less: cost of operations	(238,755)	(236,816)	(695,786)	(928,331)
Other non-interest income		660,000		660,000
Adjusted EBITDA	(238,755)	423,184	(695,786)	(268,331)
Less: JMA Profit Share
EBITDA	(238,755)	423,184	(695,786)	(268,331)
Capital expenditures
Identifiable assets	7,710,337	3,405,977		3,405,977
Total
Revenue from operations	54,688,306	55,256,887	128,243,042	175,810,850
Less: cost of operations	(55,863,490)	(51,796,196)	(136,531,447)	(161,433,198)
Other non-interest income	156,396	722,500	412,061	847,500
Adjusted EBITDA	(1,018,788)	4,183,191	(7,876,344)	15,225,152
Less: JMA Profit Share	(965,627)	(1,435,376)	(392,062)	(4,812,674)
EBITDA
Depletion, depreciation and amortization	504,719	414,837	(1,415,519)	1,217,005
Interest expense, net	(484,215)	(380,342)	(1,301,486)	(1,313,247)
Income (loss) before income taxes	(2,973,349)	1,952,636	(10,985,411)	7,882,226
Income tax benefit (expense)	1,034,798	(688,403)	3,735,040	(2,778,750)
Net income (loss)	(1,938,551)	1,264,233	(7,250,371)	5,103,476
Capital expenditures	4,182,747	2,355,811	11,255,725	8,156,298
Identifiable assets	$ 96,402,163	$ 84,855,406	$ 96,402,163	$ 84,855,406

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5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 192,351	$ 315,120
Prepaid listing fees	3,750
Prepaid related party operating expenses		624,570
Prepaid expenses, net	$ 196,101	$ 939,690

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6. Inventory (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
HOBM	$ 4,069,203	$ 5,007,576
Jet fuel	3,744,702	2,045,784
Naphtha	417,223	309,850
AGO	280,277	278,278
Chemicals	261,518	122,777
Propane	24,860	17,860
Crude oil and condensate	19,041	19,041
LPG mix	3,156	7,152
Inventories, net	$ 8,819,980	$ 7,808,318

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7. Property, Plant and Equipment, Net (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Refinery and facilities	$ 50,516,486	$ 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	54,224,861	43,896,303
Less: Accumulated depletion, depreciation and amortization	(7,649,077)	(6,234,161)
Property, plant and equipment, gross	46,575,784	37,662,142
Construction in progress	14,707,943	11,179,670
Property, plant and equipment, net	$ 61,283,727	$ 48,841,812

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8. Property, Plant and Equipment, Net (Details Narrative) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Interest cost capitalized	$ 1,776,863	$ 556,032

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8. Related Party Transactions (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015	Dec. 30, 2015
Prepaid operating expenses, related party		$ 624,570
Long-term debt, related party	$ 6,898,391
Less: Long-term debt - current portion, related party	500,000
Long-term debt - net of current portion, related party	6,398,931
Accrued interest, related party	80,000
Less: Interest payble current portion	(80,000)
Accrued interest - net of interest payable current portion, related party
LEH [Member]
Prepaid operating expenses, related party			$ 624,570
Long-term debt, related party	5,797,172
Accrued interest, related party	80,000
Ingleside [Member]
Long-term debt, related party	679,385
Jonathan Carroll [Member]
Long-term debt, related party	$ 422,374
Accrued interest - net of interest payable current portion, related party		$ 6,398,931

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8. Related Party Transactions (Details 1)	Dec. 31, 2015 USD ($)
Accounts payable, related party	$ 300,000
Ingleside [Member]
Accounts payable, related party	300,000
Jonathan Carroll [Member]
Accounts payable, related party

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8. Related Party Transactions (Details 2)	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($) $ / bbl	Sep. 30, 2015 USD ($) $ / bbl	Sep. 30, 2016 USD ($) $ / bbl	Sep. 30, 2015 USD ($) $ / bbl
Refinery operating expenses, Amount | $	$ 3,153,646	$ 2,953,528	$ 9,468,409	$ 8,420,650
Refinery operating expenses, Per bbl | $ / bbl	2.77	2.66	3.12	2.73
LEH [Member]
Refinery operating expenses, Amount | $	$ 3,028,646	$ 2,953,528	$ 8,618,409	$ 8,420,650
Refinery operating expenses, Per bbl | $ / bbl	2.66	2.66	2.84	2.73
Ingleside [Member]
Refinery operating expenses, Amount | $	$ 125,000		$ 850,000
Refinery operating expenses, Per bbl | $ / bbl	0.11	0.00	0.28	0.00

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8. Related Party Transactions (Details 3) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Refined petroleum product sales	$ 53,951,293	$ 54,924,070	$ 126,546,716	$ 174,830,292
Tank rental revenue	717,487	286,892	1,624,461	860,676
Total revenue from operations	54,688,306	55,256,887	128,243,042	175,810,850
LEH [Member]
Refined petroleum product sales	14,536,997		23,449,071
Tank rental revenue	426,000		750,000
Other Customer [Member]
Refined petroleum product sales	39,414,296	54,924,070	103,097,645	174,830,292
Tank rental revenue	291,487	286,892	874,461	860,676
Pipeline operations	$ 19,526	$ 45,925	$ 71,865	$ 119,882

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8. Related Party Transactions (Details 4) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Interest expenses under loan and guarantee, related party	$ 252,300	$ 165,008	$ 602,931	$ 165,008
LEH [Member]
Interest expenses under loan and guarantee, related party	80,000		80,000
Jonathan Carroll [Member]
Interest expenses under loan and guarantee, related party	$ 172,300	$ 165,008	$ 522,931	$ 165,008

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8. Related Party Transactions (Details Narrative) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Related Party Transactions [Abstract]
Prepaid related party operating expenses		$ 624,570
Accounts payable, related party		$ 300,000
Accounts receivable related to LEH	$ 2,869,805

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9. Long-Term Debt, Net (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Principal balance outstanding	$ 35,758,263	$ 37,172,668
Debt Issue Costs	(2,295,118)	(2,391,482)
Long-Term Debt, Net	33,463,145	34,781,186
Less: Long-term debt less unamortized debt issue costs, current portion	(32,120,782)	(1,934,932)
Long term debt	1,342,363	32,846,254
First Term Loan Due 2034 [Member]
Principal balance outstanding	24,111,986	24,643,081
Debt Issue Costs	(1,557,748)	(1,623,810)
Long-Term Debt, Net	22,554,238	23,019,271
Less: Long-term debt less unamortized debt issue costs, current portion
Second Term Loan Due 2034 [Member]
Principal balance outstanding	9,797,549	10,000,000
Debt Issue Costs	(737,370)	(767,672)
Long-Term Debt, Net	9,060,179	9,232,328
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
Term Loan Due 2017 [Member]
Principal balance outstanding	369,987	924,969
Debt Issue Costs
Long-Term Debt, Net	178,741	924,969
Capital Leases [Member]
Principal balance outstanding	178,741	304,618
Debt Issue Costs
Long-Term Debt, Net	$ 178,741	$ 304,618

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9. Long-Term Debt, Net (Details 1) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Notre Dame Debt	$ 1,638,952	$ 1,482,801
LEH Loan Agreement	80,000
Second Term Loan Due 2034	43,836	39,193
First Term Loan Due 2034	33,030	34,883
Capital leases	1,531	2,612
Term Loan Due 2017	309	4,779
Total	1,797,658	1,564,268
Less: Interest payable, current portion	(158,706)	(81,467)
Long term debt	$ 1,638,952	$ 1,482,801

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9. Long-Term Debt, Net (Details 2) - USD ($)	Sep. 30, 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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Principal balance outstanding	$ 1,342,363		$ 1,342,363		$ 32,846,254
Term Loan Due 2017 [Member]
Guaranty fees	2,158	$ 6,506	9,250	$ 6,506
Second Term Loan Due 2034 [Member]
Interest accrued	74,111		74,111
Guaranty fees	49,094	0	148,261	0
First Term Loan Due 2034 [Member]
Guaranty fees	$ 121,048	$ 142,002	$ 365,420	$ 142,002

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10. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Disclosure Text Block Supplement [Abstract]
Unearned revenue	$ 597,162	$ 781,859
Excise and income taxes payable	12,852	1,290,101
Other payable	166,314	157,714
Transportation and inspection	38,000
Board of director fees payable	133,929	86,429
Property taxes	92,678
Insurance		103,024
Genesis JMA Profit Share payable	245,255	388,364
Unrealized hedging loss	1,326,890	183,400
Accrued Expenses and Other Current Liabilities, Net	$ 3,063,080	$ 2,990,891

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11. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 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			(61,408)		(92,330)
Accretion expense	$ 28,186	$ 52,720	84,558	$ 158,655	211,375
Asset retirement obligations	2,009,014		2,009,014		1,985,864
Less: asset retirement obligations, current portion	(25,972)		(25,972)		(38,644)
Long-term asset retirement obligations, at the end of the period	$ 1,983,042		$ 1,983,042		$ 1,947,220

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11. Asset Retirement Obligations (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Liabilities settled recognized	$ 0	$ 0	$ 61,408	$ 92,330
Abandonment expense			$ 0	$ 0

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12. Treasury Stock (Details Narrative) - shares	Sep. 30, 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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Total refined petroleum product sales	$ 53,951,293	$ 54,924,070	$ 126,546,716	$ 174,830,292
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 237,009	$ 617,715	$ 621,313	$ 909,207
Concentration Risk	0.40%	1.10%	0.50%	0.50%
Naphtha
Total refined petroleum product sales	$ 11,870,484	$ 11,218,381	$ 28,183,809	$ 38,048,064
Concentration Risk	22.00%	20.40%	22.30%	21.80%
Jet Fuel
Total refined petroleum product sales	$ 15,104,900	$ 17,782,534	$ 41,150,686	$ 51,713,507
Concentration Risk	28.00%	32.40%	32.50%	29.60%
HOBM
Total refined petroleum product sales	$ 14,206,759	$ 9,609,536	$ 25,259,753	$ 40,640,975
Concentration Risk	26.40%	17.50%	20.00%	23.20%
Reduced crude
Total refined petroleum product sales		$ 50,407	$ 3,791,919	$ 50,407
Concentration Risk	0.00%	0.10%	3.00%	0.00%
AGO
Total refined petroleum product sales	$ 12,532,141	$ 15,645,497	$ 27,539,236	$ 43,468,132
Concentration Risk	23.20%	28.50%	21.70%	24.90%

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13. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Concentration Risk	100.00%	100.00%	100.00%	100.00%
FDIC insurance limit					$ 250,000
Excess of the FDIC insurance limit	$ 9,345,560		$ 9,345,560		$ 19,594,883
LEH [Member]
Concentration Risk	27.00%		19.00%
Concentration risk accounts receivable	$ 2,900,000		$ 2,900,000
Sales Revenue [Member] | Four customers [Member]
Concentration Risk	70.00%		64.00%
Concentration risk accounts receivable	$ 6,700,000		$ 6,700,000
Account Receivable			$ 5,500,000
Sales Revenue [Member] | Three customers [Member]
Concentration Risk				55.00%
Concentration risk accounts receivable		$ 4,400,000		$ 4,400,000
Sales Revenue [Member] | Five customers [Member]
Concentration Risk		81.00%
Account receivable [Member] | Five customers [Member]
Concentration risk accounts receivable		$ 5,700,000		$ 5,700,000

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14. Leases (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Leases, Operating [Abstract]
Rent expense	$ 33,251	$ 29,857	$ 92,966	$ 112,746

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15. Income Taxes (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Current:
Federal		$ (37,620)		$ (122,863)
State		(36,102)		(148,656)
Deferred:
Federal	1,034,798	(614,681)	3,735,040	(2,507,231)
Income tax benefit (expense)	$ 1,034,798	$ (688,403)	$ 3,735,040	$ (2,778,750)

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15. Income Taxes (Details 1) - USD ($)	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Balance	$ 29,333,503		$ 19,231,390	$ 22,912,701
Net operating loss carryforwards utilized	2,487,642	$ 4,230,763	5,871,350	(3,681,311)
Balance	31,821,145	29,333,503		19,231,390
Pre-Ownership Change [Member]
Balance	9,614,449		9,614,449	10,766,912
Net operating loss carryforwards utilized				(1,152,463)
Net operating losses
Balance	9,614,449	9,614,449		9,614,449
Post-Ownership Change [Member]
Balance	19,719,054		9,616,941	12,145,789
Net operating loss carryforwards utilized	2,487,642	4,230,763	$ 5,871,350	(2,528,848)
Balance	$ 22,206,696	$ 19,719,054		$ 9,616,941

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15. Income Taxes (Details 2) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 13,089,512	$ 8,815,794
Start-up costs (Nixon Facility)	1,407,697	1,510,699
Asset retirement obligations liability/deferred revenue	714,961	717,723
Unrealized hedges	451,141	62,356
AMT credit and other	257,323	302,086
Total deferred tax assets	15,920,634	11,408,658
Deferred tax liabilities:
Fair market value adjustments	(46,116)	(46,116)
Unrealized hedges
Basis differences in property and equipment	(6,261,919)	(5,484,983)
Total deferred tax liabilities	(6,308,035)	(5,531,099)
Deferred tax assets, net	9,612,599	5,877,559
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets, net	$ 7,342,277	$ 3,607,237

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15. Income Taxes (Details Narrative) - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets	$ 7,300,000		$ 3,600,000
Valuation allowance	$ 2,300,000	$ 2,300,000

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16. Earnings per share (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ (1,938,551)	$ 1,264,233	$ (7,250,371)	$ 5,103,476
Basic and diluted income per share	$ (0.19)	$ 0.12	$ (0.69)	$ 0.49
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,464,715	10,453,802	10,460,849	10,451,168

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17. Fair Value Measurement (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Financial assets (liabilties):
Commodity contracts	$ (1,326,890)	$ (183,400)
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Financial assets (liabilties):
Commodity contracts	(1,326,890)	(183,400)
Significant Other Observable Inputs (Level 2) [Member]
Financial assets (liabilties):
Commodity contracts	0	0
Significant Unobservable Inputs (Level 3) [Member]
Financial assets (liabilties):
Commodity contracts	$ 0	$ 0

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17. Fair Value Measurement (Details Narrative) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of long term debt and short-term notes payable	$ 39,758,263	$ 37,172,668

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18. Inventory Risk Management (Details) - Refined products - net short (long) positions	Sep. 30, 2016 shares
Volume in Thousands of barrels
Notional Contract Volumes 2016	290,000
Notional Contract Volumes 2017	0
Notional Contract Volumes 2018	0

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18. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ (1,326,890)		$ (1,326,890)		$ (183,400)
Cost of refined products sold	$ 770,838	$ 2,205,291	$ (2,588,734)	$ 1,762,582

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19. Commitments and Contingencies (Details Narrative) - USD ($)	Sep. 30, 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