10-K 1 bdco_10k.htm ANNUAL REPORT bdco_10k.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
­
FORM 10-K
(Mark One)
 þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2013
 
or
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from             to            .

Commission File No. 0-15905
 
BLUE DOLPHIN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
 
Delaware
 
73-1268729
State or other jurisdiction of incorporation or organization
 
(I.R.S. Employer Identification No.)

801 Travis Street, Suite 2100
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
 (713) 568-4725
Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
Name of each exchange on which registered
Common Stock, par value $0.01 per share
OTCQX

Securities registered pursuant to Section 12(g) of the Act:
 
(Title of class)
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller Reporting Company þ

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

The aggregate market value of shares of common stock held by non-affiliates of the registrant was $8,843,968 based on the number of shares of common stock held by non-affiliates and the last reported sale price of the registrant's common stock on December 31, 2013.
 
Number of shares of common stock, par value $0.01 per share outstanding as of March 31, 2014:  10,430,973

 


 
 
 
 
 
BLUE DOLPHIN ENERGY COMPANY
FORM 10-K REPORT INDEX
 
PART I       5  
         
    ITEM 1.
BUSINESS
   
5
 
           
    ITEM 1A.
RISK FACTORS
   
13
 
           
    ITEM 1B.
UNRESOLVED STAFF COMMENTS
   
20
 
           
    ITEM 2.
PROPERTIES
   
20
 
           
    ITEM 3.
LEGAL PROCEEDINGS
   
22
 
           
    ITEM 4.
MINE SAFETY DISCLOSURES
   
22
 
           
PART II
    23  
           
   ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
   
23
 
           
    ITEM 6.
SELECTED FINANCIAL DATA
   
23
 
           
    ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
   
24
 
           
    ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
   
35
 
           
    ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
   
36
 
           
    ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
   
66
 
           
    ITEM 9A.
CONTROLS AND PROCEDURES
   
66
 
           
    ITEM 9B.
OTHER INFORMATION
   
66
 
           
PART III
    67  
           
   ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
   
67
 
           
    ITEM 11.
EXECUTIVE COMPENSATION
   
70
 
           
    ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
   
72
 
           
    ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
   
73
 
           
    ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
   
73
 
           
PART IV
    74  
           
   ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
   
74
 
           
SIGNATURES
   
80
 
 
 
 
2

 
 
FORWARD LOOKING STATEMENTS

As provided by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, certain statements included throughout this Annual Report on Form 10-K, and in particular under the sections entitled “Part I, Item 1. Business,” “Part I, Item 3. Legal Proceedings” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” relating to matters that are not historical fact are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements.
 
Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized, or materially affect our financial condition, results of operations and cash flows.
 
Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:
 
 
changes in the general economic conditions;
changes in the underlying demand for our products;
fluctuations of crude oil inventory costs and refined petroleum products inventory prices and their effect on our refining margins;
our dependence on Genesis Energy, LLC (“Genesis”) and its affiliates for continued financing, sourcing of crude oil inventory and marketing of our refined petroleum products;
the early termination of our agreements with Genesis and its affiliates;
our dependence on Lazarus Energy Holdings, LLC (“LEH”) for continued financing and management of all of our subsidiaries and the operation of all of our assets, including the Nixon Facility, pursuant to the Management Agreement;
our ability to generate sufficient funds from operations or obtain financing from other sources;
failure to comply with certain financial covenants related to certain of our long-term indebtedness;
regulatory changes that reduce the allowable sulfur content for commercially sold diesel in the United States, which will require us to incur significant capital upgrades and could have a material adverse effect on our results of operations, financial condition and cash flows;
availability and cost of renewable fuels for blending and Renewable Identification Numbers (“RINs”) to meet Renewable Fuel Standards ("RFS") obligations;
strict laws and regulations regarding employee and business process safety to which we are subject, the compliance failure of which could have a material adverse effect on our results of operations and financial condition;
potential increased indebtedness, which may reduce our financial flexibility;
regulatory restrictions on greenhouse gas emissions, which could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition;
access to less than desired levels of crude oil for processing at the Nixon Facility;
our dependence on a small number of customers for a large percentage of our revenues;
accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our operations;
potential downtime of the Nixon Facility, which could result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations;
the geographic concentration of the Nixon Facility, which creates a significant exposure risk to the regional economy;
competition from larger companies;
infrastructure limitations;
dangers inherent in our operations, such as fires and explosions, which could cause disruptions and expose us to potentially significant losses, costs and liabilities and significantly reduce our liquidity;
the effects of Genesis’ hedging of our refined petroleum products and crude oil inventory and exposure to the risks associated with volatile crude oil prices;
retention of key personnel;
insurance coverage that may be inadequate or expensive;
our potential reorganization from a publicly traded “C” corporation to a publicly traded master limited partnership;
performance of third-party operators for our oil and gas properties;
costs associated with abandonment of our pipelines and oil and gas properties; and
changes in and compliance with taxes, which could adversely affect our performance.
 
 


 
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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 by the securities laws to do so.


 

Remainder of Page Intentionally Left Blank

 
 
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PART I
 
 ITEM 1.  BUSINESS

Company Overview

Blue Dolphin Energy Company (www.blue-dolphin-energy.com), a Delaware corporation (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) was formed in 1986 as a holding company. We conduct substantially all of our operations through our wholly-owned subsidiaries.  We are primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 56 acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  As part of our refinery business segment we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility.  We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refinery Operations
 
Our primary business is the refining of crude oil and condensate into marketable finished and intermediate products at the Nixon Facility, which has a current operating capacity of approximately 15,000 barrels (“bbls”) per day (“bpd”). The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, jet fuel treater, approximately 120,000 bbls of crude oil storage capacity, approximately 148,000 bbls of refined product storage capacity and related loading and unloading facilities and utilities.

The Nixon Facility is operated as a “topping unit,” processing light crude oil and condensate primarily from the Eagle Ford Shale formation in South Texas.  We purchase the light crude oil and condensate for the Nixon Facility under an exclusive supply agreement with GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis.  The light crude oil and condensate is refined into finished products such as diesel and jet fuel and intermediate products such as naphtha, liquefied petroleum gas (“LPG”) and atmospheric gas oil.  Finished products are sold in nearby markets and intermediate products are sold to wholesalers and nearby refineries for further blending and processing.  Crude oil and condensate is currently received at the Nixon Facility by truck, however, the facility has the ability to receive feedstock by pipeline.  Our refined products are sold and delivered primarily by truck.

Crude Oil Refining Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil into usable or refined petroleum products such as gasoline, diesel, jet fuel and other products. The crude oil refining process for most refineries involves numerous stages to create refined products, however, as a “topping unit” the Nixon Facility only engages in the first stage of the crude oil refining process. Refining is primarily a margin-based business where the crude oil (and other feedstocks) and refined products are commodities with fluctuating prices. In order to increase profitability, it is important for a refinery to both maximize and optimize the yields of its most profitable products and minimize the costs of crude oil (and other feedstocks) and operating expenses, and to do so without compromising safety and environmental performance. According to the U.S. Energy Information Administration (the “EIA”), as of January 1, 2013, there were 139 oil refineries operating in the United States, 27 of which were in Texas. Crude oil supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a given refinery’s location.

Refinery Raw Material Supply

Crude oil and condensate derived from surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s input.  In August 2011, we entered into the Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) with GEL whereby we exclusively obtain all of the crude oil and condensate for the Nixon Facility through GEL, other than the crude oil and condensate purchased from any other supplier with the prior consent of GEL. All crude oil and condensate supplied pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described herein (see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis”).  In addition, we have granted GEL right of first refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement.

Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years expiring on August 12, 2014.  On October 30, 2013, Lazarus Energy, LLC (“LE”) entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam Services, Inc. (“Milam”)(the “October 2013 Letter Agreement”), effective October 24, 2013.  In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.

 
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Refinery Customers

Customers for our finished and intermediate petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers. Many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our finished and intermediate petroleum products. For the year ended December 31, 2013, our five largest customers accounted for approximately 92% of our refined petroleum products sales.  For the year ended December 31, 2012, our four largest customers accounted for approximately 84% of our refined petroleum products sales.

Petroleum Refining Market and Competition

The petroleum refining and marketing industry continues to be highly competitive. Many of our principal competitors are integrated, multi-national oil companies (e.g., Valero, Chevron, ExxonMobil, Shell and ConocoPhillips) and other major independent refining and marketing entities that operate in our market areas. The principal competitive factors affecting us are crude oil and other feedstock costs, refinery efficiency, operating costs, refinery product mix and product distribution/transportation costs.  Because of their diversity, integration of operations and larger capitalization, these competitors may be better able to withstand volatile market conditions, compete on the basis of price, obtain crude oil in times of shortage and bear the economic risk inherent in all phases of the refining industry due to their geographic diversity, operational complexity and resources.

We operate primarily in the Eagle Ford Shale in South Texas supplying finished and intermediate petroleum products to the area from our Nixon Facility. The market for our finished and intermediate petroleum products is generally supplied by a number of refiners, including large integrated oil companies or independent refiners. These larger companies typically have greater resources and may have greater flexibility in responding to volatile market conditions or absorbing market changes.

Refinery Operations Business Strategy

We are dedicated to maintaining safe, efficient and reliable refinery operations, improving liquidity and profitability, and focusing on safety and environmental stewardship.   Throughout 2013, we took a number of steps to more effectively operate the Nixon Facility and manage the spread between our cost to acquire crude oil and the price of the refined petroleum products that we ultimately sell, as follows:

  
Safety and Environmental Management – We implemented programs and procedures across the company for managing safety and environmental matters with a focus on the assignment of responsibilities, sound risk management and decision-making, efficient and cost-effective planning and operations and regulatory compliance.  We also completed an assessment of process safety management (“PSM”) standards at the Nixon Facility.  Improving our PSM standards and developing a PSM  program at the Nixon Facility, which is designed to address all aspects of OSHA guidelines for developing and maintaining a comprehensive PSM program., is an integral part of our safety and environmental management strategy going forward;

  
Improved Product Mix – The Nixon Facility began producing jet fuel – the Nixon Facility’s fifth commercially saleable product – in mid-September 2013.  Jet fuel is produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream.  Production of jet fuel, which is considered a higher value product, significantly upgrades the value of the naphtha component.  We plan to significantly increase the production of jet fuel during 2014;

  
Naphtha Stabilizer and Depropanizer Units Refurbishment – We continued the refurbishment of certain components of Nixon Facility, including the naphtha stabilizer and depropanizer units, which we anticipate will: (i) improve the overall quality of the naphtha that we produce, (ii) allow higher recovery of lighter products that can be sold as a liquefied petroleum gas (“LPG”) mix, and (iii) increase the amount of throughput that can be processed by the Nixon Facility.  The estimated cost to refurbish the naphtha stabilizer and depropanizer units is approximately $1.5 million; and

  
Nixon Facility Improvements -- We continued to enhance our condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, such as installing new laboratory equipment and a new caustic system and upgrading loading bay meters.

 
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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 in the U.S. Gulf of Mexico. Producers and shippers are charged a fee based on anticipated throughput volumes.  Our pipeline transportation operations represented less than 1% of total revenue for the years ended December 31, 2013 and 2012.

Oil and Gas Exploration and Production

Our oil and gas exploration and production assets, which include leasehold interests in properties in the U.S. Gulf of Mexico and previously included a leasehold interest in Indonesia, were uneconomic for the years ended December 31, 2013 and 2012 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company, a wholly owned subsidiary (“BDEX”), completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.  Our oil and gas exploration and production operations represented less than 1% of total revenue for the years ended December 31, 2013 and 2012.

Recent Developments

WBI Asset Sale Agreement.  On February 25, 1999, WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), acquired from Blue Dolphin Pipe Line Company  (“BDPL”), a 1/6th, undivided beneficial interest in the Blue Dolphin Pipeline System, Galveston Area Block 350 Pipeline, and the Omega Pipeline (the “Pipeline Assets”).  On March 1, 1999, WBI and BDPL, as owners of the Pipeline Assets, engaged BDPL to operate certain pipeline systems within the Pipeline Assets (the “System”) and entered into an operating agreement governing the operation of the System (the “Operating Agreement”).  On February 5, 2014, WBI and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”), whereby BDPL reacquired WBI’s 1/6 interest in the Pipeline Assets, effective October 31, 2013.

Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash and $850,000 in the form of a bond in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  Effective October 31, 2013, WBI and BDPL mutually agreed to terminate the Operating Agreement whereby BDPL is now the sole owner and operator of the Pipeline Assets therein.

Master Easement Agreement - BDPL and FLNG Land.  On December 11, 2013 (the “Effective Date”), BDPL and FLNG Land, II, Inc., a Delaware corporation (“FLNG”), entered into a Master Easement Agreement (the “Master Easement Agreement”) whereby BDPL is providing FLNG with: (i) free and uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG (the “Access Easement”) and (ii) a perpetual permanent pipeline easement and right of way across certain property of BDPL to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”).  As initial consideration for the grant of the Easements, FLNG paid BDPL the sum of $250,000 (the “Initial Payment”) on the Effective Date.  FLNG has the option to terminate the Master Easement Agreement within ten (10) months of the Effective Date.  If FLNG commences improvements within the Access Easement or commences construction within the Pipeline Easement (the “Commencement Date”), FLNG shall make a second payment of $250,000 to BDPL (the “Second Payment”).

If FLNG elects to make the Second Payment, then on or before the first anniversary of the Commencement Date through the greater of: (i) the fifth anniversary of said date or (ii) the date on which the third of FLNG’s planned liquefaction pre-treatment train facilities has reached completion sufficient to permit its start-up and initial operational testing, FLNG shall make annual payments of $500,000 (“the Annual Payments”) to BDPL. Upon delivery of the Initial Payment, Second Payment, and each of the remaining Annual Payments, the Easements shall be fully paid for by FLNG.  On the anniversary of the date when the final Annual Payment is made, FLNG will pay to BDPL the sum of $10,000 annually for so long as FLNG desires to use the Access Easement.  The terms of the Easements are perpetual, unless terminated by FLNG prior to the Commencement Date or if FLNG elects to permanently cease use of the Access Easement or Pipeline Easement, as applicable.

Ongoing Acquisition and Disposition Activities
 
Consistent with our growth strategy, we are continuously engaged in discussions with potential sellers of assets, including Lazarus Energy Holdings, LLC (“LEH”), our majority stockholder, regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. These acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only potential buyer or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets and operations which, if acquired, could have a material effect on our financial condition and results of operations and require special financing.

 
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The closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts will be successful. Although we expect the acquisitions we make to be accretive in the long-term, we can provide no assurance that our expectations will ultimately be realized.

Intellectual Property

We rely on intellectual property laws to protect our brand, as well as those of our subsidiaries. “Blue Dolphin” is a registered trademark in the U.S. in name and logo form. “Petroport” is a registered trademark in the U.S. in name form. In addition, www.blue-dolphin.com and www.blue-dolphin-energy.com are registered domain names.

Employees

In connection with Blue Dolphin’s acquisition of LE in February 2012 (the “LE Acquisition”), we entered into a Management Agreement with LEH (the “Management Agreement”) pursuant to which LEH manages all of our subsidiaries and operates all of our assets, including the Nixon Facility. Under the Management Agreement, all Blue Dolphin personnel work for and are paid directly by LEH.  LEH bills Blue Dolphin at cost for certain personnel associated with BDPL.

Governmental Regulation

All of our operations and properties are subject to extensive and complex federal, state, and local environmental, health, and safety statutes, regulations, and ordinances governing, among other things, the generation, storage, handling, use and transportation of petroleum, solid wastes, hazardous wastes, and hazardous substances; the emission and discharge of materials into the environment and environmental protection; waste management; characteristics and composition of diesel and other fuels; and the monitoring, reporting and control of greenhouse gas emissions. These laws impose certain obligations on our operations, including requiring the acquisition of permits and authorizations to conduct regulated activities, restricting the manner in which regulated activities are conducted, limiting the quantities and types of materials that may be released into the environment, and requiring the monitoring of releases of materials into the environment.

Failure to comply with environmental, health or safety laws and our permits or other authorizations issued under such laws could result in fines, civil or criminal penalties or other sanctions, injunctive relief compelling the installation of additional controls, or a revocation of our permits and the shutdown of our facilities.

We cannot predict the extent to which additional environmental, health, and safety laws will be enacted in the future, or how existing or future laws will be interpreted with respect to our operations. Many environmental, health, and safety laws and regulations are becoming increasingly stringent. The cost of compliance with and governmental enforcement of environmental, health, and safety laws may increase in the future. We may be required to make significant capital expenditures or incur increased operating costs to achieve compliance with applicable environmental, health, and safety laws.  This Governmental Regulation section should be read in conjunction with the "Forward-Looking Statements" and Part I, Item 1A “Risk Factors” sections in this Form 10-K , which discuss our expectations regarding future events, results or outcomes based on currently available information.

The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 (the “Energy Acts of 2005 and 2007”). Pursuant to the Energy Acts of 2005 and 2007, the Environmental Protection Agency (the “EPA”) issued Renewable Fuels Standards (“RFS”) that mandate the blending of renewable fuels into refined petroleum fuel products. Although the Nixon Facility is currently subject to this requirement, we have applied for a hardship exemption based on the Nixon Facility’s small refiner status. The EPA establishes new volume requirements and associated percentage standards on an annual basis that subject refineries to RFS. The volume requirements and associated percentage standards increase through 2022, when all facilities will be subject to the requirements.

The Federal Clean Air Act (the “CAA”). The CAA, its amendments and implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect our crude oil and condensate processing operations and impact certain emissions sources located offshore. Under the CAA, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations. The EPA has, in the past, targeted petroleum refineries as part of a nationwide enforcement initiative, and refineries remain high-visibility targets for enforcement under the CAA. In 1992, the EPA published a list of source categories (industry groups) that emit one or more of a list of 188 hazardous air pollutants (“HAPs”), also known as air toxics. The list of industry groups includes petroleum refineries because they are considered to be a major source of HAP emissions. The EPA developed standards that require the application of maximum achievable control technology (“MACT”) to help control HAP emissions. The Petroleum Refinery MACT standard applies to petroleum refining process units and related emission points. We are required to obtain permits, as well as to test, monitor, report and implement control requirements. In addition, our operations are subject to a number of New Source Performance Standards (“NSPS”) regulations. For example, in September 2012, the EPA issued final revisions to the NSPS for process heaters and flares at petroleum refineries. The final NSPS regulate emissions of nitrogen oxide from process heaters and emissions of sulfur dioxide from flares. The final rule also establishes work practice and monitoring standards for flares. In addition, air permits incorporating stringent control technology requirements are required for our refining operations that result in the emission of regulated air contaminants.

 
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The CAA also authorizes the EPA to require modifications in the formulation of refined fuel products. In 2007, the EPA issued a second Mobile Source Air Toxics standard (the “MSAT II”) that required significant reductions in the sulfur content in gasoline and diesel fuel. These standards required most refineries to reduce the sulfur content in diesel to 15 parts per million (“ppm”) and gasoline to 30 ppm. Low sulfur (500 ppm) and ULSD fuel is expected to be phased in for diesel engines in June 2014. When implemented for diesel, the MSAT II requirements may require us to undergo additional permitting and/or incur capital expenditures to meet the new requirements. We can continue to sell low sulfur distillates to other refineries and blenders as a feedstock in the United States and as a finished petroleum product to other countries after the new standards are implemented. We do not currently manufacture gasoline.

In 2007 the U.S. Supreme Court held in Massachusetts v. EPA that greenhouse gas emissions may be regulated as an air pollutant under the CAA. In December 2009, the EPA published a finding that greenhouse gas emissions present an endangerment to human health and the environment because emissions of such gasses are contributing to changes in climate. The EPA has since issued regulations that require a reduction in emissions of greenhouse gases from motor vehicles and that require greenhouse gas emission permits for certain sources. Specifically, the EPA has adopted regulations under existing provisions of the CAA establishing Prevention of Significant Deterioration (“PSD”) construction and Title V operation permits requiring reviews for greenhouse gasses for certain large, stationary sources. In September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources, including refineries. In addition, pursuant to a December 23, 2010 settlement agreement EPA was required to propose by December 10, 2011, NSPS for greenhouse gas emissions for refineries and to finalize such rules by November 15, 2012. To date, however, the EPA has not initiated that rulemaking. The adoption of future legislation limiting greenhouse gas emissions could cause us to incur additional compliance costs and may affect the demand for our products.

Occupational Safety and Health Administration (“OSHA”). In 2007, OSHA launched the National Emphasis Program for Petroleum Refineries (“RNEP”). The RNEP requires inspections of all refineries for compliance with process safety management regulations. Under the directive, our crude oil and condensate processing assets are subject to inspections that may last from two to six months, including one to three months on-site. Inspectors focus on checking process safety management implementation and records targeting specific process units and strategically sampling equipment, records and personnel. All of our operations are subject to OSHA’s standards for safe and healthful working conditions for personnel.

The Federal Water Pollution Control Act, also known as the Clean Water Act (the “CWA”). The CWA and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants, including spills and leaks of oil and other substances, into the water. The CWA and analogous state laws affect our crude oil and condensate processing operations, petroleum storage and terminaling operations, pipeline operations and exploration and production activities. The CWA prohibits the discharge of pollutants to waters of the United States except as authorized by the terms of a permit issued by the EPA or a state agency with delegated authority. Spill prevention, control, and countermeasure (“SPCC”) requirements mandate the use of structures, such as berms and other secondary containment, to prevent hydrocarbons or other pollutants from reaching a jurisdictional water in the event of a spill or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA or analogous state laws and regulations.
 
The Oil Pollution Act of 1990 (the “OPA”). The OPA and regulations promulgated thereunder include a variety of requirements related to the prevention of oil spills and impose liability for damages resulting from such spills. OPA imposes liability on owners and operators of onshore and offshore facilities and pipelines for removal costs and certain public and private damages arising from a spill. OPA establishes a liability limit for onshore facilities of $350 million and offshore facilities of $75 million plus all clean-up costs. OPA establishes lesser liability limits for vessels depending upon their size. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction or operating regulations. If a party fails to report a spill or cooperate in the clean-up, liability limits do not apply. OPA imposes ongoing requirements on responsible parties, including proof of financial responsibility for potential spills. In October 1996, the U.S. Congress enacted the Coast Guard Authorization Act of 1996 (P.L. 104-324), which amended OPA to establish requirements for evidence of financial responsibility for certain offshore facilities. The evidence of financial responsibility amount required is $35 million for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. We currently maintain the statutory $35 million coverage. While our financial responsibility requirements under OPA may be amended to impose additional costs, we do not expect the impact of such a change to be any more burdensome on us than on others similarly situated.

 
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Outer Continental Shelf Lands Act (the “OCSLA”). Our pipeline operations and exploration and production activities within federal waters are subject to the requirements of OCSLA, which is administered by the Bureau of Ocean Energy Management (the “BOEM”) and the Bureau of Safety and Environmental Enforcement (the “BSEE”).  BOEM oversees offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies. BSEE is responsible for safety and environmental oversight of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production, inspections, offshore regulatory programs and oil spill response compliance.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”). CERCLA imposes liability, without regard to fault or the legality of the original conduct, on parties the statute defines as responsible for the release or threatened release of a “hazardous substance” into the environment. Responsible parties, which include the present owner or operator of a site where the release occurred, the owner or operator of the site at the time of disposal of the hazardous substance and persons that disposed of or arranged for the disposal of a hazardous substance, are liable for response and remediation costs and for damages to natural resources. Petroleum and natural gas are excluded from the definition of hazardous substances; however, this exclusion does not apply to all materials used in our operations. State statutes impose similar liability. At this time, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA or similar state statute.

The Federal Resource Conservation and Recovery Act (“RCRA”). RCRA and its state counterparts regulate solid and hazardous wastes and impose civil and criminal penalties for improper handling and disposal of such wastes. EPA and various state agencies have promulgated regulations that limit the disposal options for such wastes. Certain wastes generated by our oil and gas operations are currently exempt from regulation as hazardous wastes, but are subject to non-hazardous waste regulations. In the future these wastes could be designated as hazardous wastes under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements.

We currently own or lease, or have in the past owned or leased, various properties used for the crude oil and processing assets, petroleum storage and terminaling assets, pipeline assets and oil and gas leasehold interests used to process and store solid and hazardous wastes. Although our past operating and disposal practices at these properties were standard for the industry at the time, hydrocarbons or other substances may have been disposed of or released on or under these properties or on or under other locations. In addition, many of these properties have been operated by third parties whose waste handling activities were not under our control. These properties and any waste disposed thereon may be subject to CERCLA, RCRA, and state laws which could require us to remove or remediate wastes and other contamination or to perform remedial plugging operations to prevent future contamination.
 
Environmental

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (26) Commitments and Contingencies” of this report for a description of our environmental activities.

Available Information

The SEC maintains and makes available public records, which includes reports filed by regulated companies and individuals, through conventional and electronic reading rooms. The SEC’s conventional reading room is located at 100 F Street, Northeast, Washington, D.C. 20549 and can be reached at (202) 551-8300. The SEC’s electronic reading room, which maintains records created by the SEC on or after November 1, 1996, is available online at http://www.sec.gov/foia/efoiapg.htm. Reports filed with the SEC by regulated entities and individuals are available at http://www.sec.gov/edgar/searchedgar/webusers.htm. We also make our public filings available on our website (http://www.blue-dolphin-energy.com) as soon as reasonably practicable after such material is filed, or furnished, to the SEC. A copy of our filings will also be furnished free of charge upon request.

Information about each of our directors, our Audit Committee Charter and our code of conduct and code of ethics are available on our website. Information contained on our website is not part of this report.

 
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Glossary of Industry Terms

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

Atmospheric Gas Oil. 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. In-blends atmospheric gas oil, often abbreviated 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.

Bbl. One stock tank barrel, 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.

Bpd. Barrels per day.

Condensate. Liquid hydrocarbons that are produced in conjunction with natural gas.  Condensate is chemically more complex than liquefied petroleum gas.  Although condensate is sometimes similar to crude oil or naphtha, it is usually lighter.

Cooling Tower. A structure that cools heated refining process water by circulating the water through a series of louvers and baffles through which cool air is forced by large fans.

Crude Oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. 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. There are primarily five types of crude – West Texas Intermediate (“WTI”), Light Crude, Sweet Crude, Sour Crude and Brent Crude. See definitions of WTI, Light Crude, Sweet Crude and Sour Crude.

Crude Unit. The refinery processing unit where initial crude oil distillation takes place. See definition of Topping Unit.

Cut. One or more crude oil compounds that vaporize and are extracted within a certain temperature range during the crude distillation process.

Depropanizer. A distillation column that is used to isolate propane from a mixture containing butane and other heavy components.

Desalting. Removal of salt from crude oil. Desalting is preferably performed prior to commercialization of the crude; must be performed prior to refining.

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 (e.g., jet fuel, gasoline, kerosene, and naphtha), (ii) light oils or middle distillates, (iii) medium oils, and (iv) heavy fuel oils.

Distillation. The first step in the refining process whereby crude oil is heated in the base of a distillation tower. As the temperature increases, the crude's 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.

Distillation Tower. A tall column-like vessel in which crude oil is heated and its vaporized components distilled by means of distillation trays.

Exchanger (Heat Exchanger). A device used to transfer heat from one process liquid to another.

Feedstocks. Processed oil destined for further processing other than blending. It is transformed into one or more components and/or finished products.

Fractionation. The separation of crude oil into its more valuable and usable components through distillation.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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.

 
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Heat Exchanger. See definition for Exchanger.

Intermediate Petroleum Products.  A 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 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.  Jet fuel is a white product, so-called because it is transparent.

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. Crude oil with a low wax content.

Liquefied Petroleum Gas (“LPG”).  Manufactured during the refining of crude oil. LPG burns relatively cleanly with no soot and very few sulfur emissions.

MMcf. One million cubic feet of gas.

Naphtha. A refined or partly refined light distillate fraction of crude oil. Blended further or mixed with other materials it makes high-grade motor gasoline or jet fuel. It is also a generic term applied to the lightest and most volatile petroleum fractions.

Net Revenue Interest.  The percentage of production to which the owner of a working interest is entitled.

Non-Road, Locomotive and Marine Diesel Fuel (“NRLM”).  Commonly referred to as “off-road diesel.” Used in diesel engines for construction, agricultural, stationary engine, locomotive and marine operations. Typically, off-road diesel has a higher sulfur content than on-road diesel.

Overriding Royalty Interest. An interest in oil and gas produced at the surface, free of the expense of production that is in addition to the usual royalty interest reserved to the lessor in an oil and gas lease.

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.

Ppm.  Parts per million.

Propane. A by-product of natural gas processing and petroleum refining. Propane is one of a group of liquefied petroleum gases. The others include butane, propylene, butadiene, butylene, isobutylene and mixtures thereof. See definition of Liquefied Petroleum Gas.

Recommissioning. While commissioning of a new plant facility or refinery helps ensure correct operation of its major systems when first installed, recommissioning helps to restore an existing plant facility or refinery to its originally intended operating performance. Both processes comprise the integrated application of a set of engineering techniques and procedures to check, inspect and test every operational component of the project, from individual functions such as instruments and equipment, up to complex amalgamations, such as modules, subsystems and systems.

Refined Petroleum Products. Refined petroleum products are derived from crude oils 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. Following the refining process, the products are transported to terminals or local distribution centers for sale to various end-users and consumers.

Refinery. A plant where crude oil is separated and transformed into marketable refined petroleum products.

Separation. The separation of the different hydrocarbons present in crude oil depending on their respective boiling ranges. This process takes place in a distillation column.

 
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Sour Crude. Crude oil containing sulfur content of more than 0.5%. Usually processed into heavy oil such as diesel.

Stabilizer. 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%. Commonly used for processing into gasoline.

Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal or natural gas. Also produced as a byproduct 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 (Atmospheric Distillation). Conducts the initial transformation of crude oil at a refinery. The topping unit heats crude oil at atmospheric pressure to accomplish the first rough distillation cut. 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.

Turnaround. Scheduled large-scale maintenance activity wherein an entire process unit is taken offline for a week or more for comprehensive revamp and renewal.

Ultra-low-sulfur Diesel (“ULSD”)(On-Road Diesel). Diesel fuel with substantially lowered sulfur content (currently 15 ppm). Primarily used as commercial transportation fuel.

Undivided Interest. A form of ownership interest in which more than one person concurrently owns an interest in the same oil and gas lease or pipeline and in which the interests of the parties are not specified whether by percentage or portion of the property.

West Texas Intermediate (“WTI”). A grade of crude oil used as a benchmark in oil pricing. Described as intermediate because of its relative mid-range density and mid-range sulfur content.

Working Interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production after the corresponding percentage of operational costs and royalties are paid.

ITEM 1A.  RISK FACTORS

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks we face. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial condition, operating results and/or cash flows.

Risks Related to our Business

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, cash flows and liquidity.

Our refining earnings, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business.  To increase earnings it is important to maximize and optimize the yields of finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

 
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Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, diesel, and other refined products. Such supply and demand are affected by, among other things:

changes in global and local economic conditions;
domestic and foreign demand for fuel products, especially in the United States, China and India;
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported into the United States;
availability of and access to transportation infrastructure;
utilization rates of U.S. refineries;
the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;
development and marketing of alternative and competing fuels;
commodities speculation;
natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;
federal and state government regulations and taxes; and
local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

Refining margins are volatile, and a reduction in anticipated refining margins will adversely affect the amount of cash we will have available for working capital.

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our refined petroleum products prices and the prices for crude oil. The cost to acquire crude oil and the price at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control.

The prices at which we sell refined petroleum products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our refined petroleum products segment margins will fall unless we are able to pass along these price increases to our wholesale customers. Increases in selling prices for refined petroleum products typically lag behind the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period of time.

Our operations are highly dependent on our relationship with Genesis and LEH, and, if we are unable to successfully maintain these relationships, our operations, liquidity and financial condition may be harmed.

We are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil, transportation of crude oil, provision of accounting and other services, joint marketing of our refined petroleum products and funding of renovations, expansion and other capital expenditures relating to the Nixon Facility. Certain of these agreements with Genesis and its affiliates have an initial term of three years and successive one-year renewals until August 12, 2019 unless sooner terminated by Genesis or its affiliates with 180 days prior written notice.  Further, we have an understanding with Genesis relating to an inventory risk management system, which is intended to reduce the commodity price risk of our finished products inventory and generate a more consistent gross margin for each barrel of refined product.
 
LEH manages all of our subsidiaries and operates all of our assets, including the Nixon Facility, pursuant to the Management Agreement.  The Management Agreement expires on the earliest to occur of: (a) the termination date of a certain agreement with a Genesis affiliate, which has an initial term of three years and successive one-year renewals until August 12, 2019 unless sooner terminated by the Genesis affiliate with 180 days prior written notice, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party.
 
These agreements and understandings require us to have a close working relationship with Genesis and LEH in order for us to be successful in fully executing our business strategy. If we are unable to maintain these relationships or our relationships are not on good terms, it could have a material adverse effect on our operations, liquidity and financial condition.

Genesis and LEH may, but are not required to, fund our working capital requirements.

Historically, we have used a portion of our cash reserves and revenue from operations to fund our working capital requirements. To the extent that we are unable to fund our working capital requirements from cash reserves and revenue from operations, we have relied on Genesis and LEH for our working capital requirements. As of December 31, 2013, working capital requirements financed by Genesis and LEH was $2,538,077 and $3,659,340, respectively. In the event our working capital requirements are not funded by Genesis or LEH, or we are otherwise unable to secure sufficient liquidity to support our short term and/or long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which may have a material adverse effect on our results of operations or liquidity.

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

Historically, we have used a portion of our cash reserves to fund our working capital requirements that were not funded from our operations.  Most recently, we have relied on advances under the Construction Funding Agreement and revenue from operations, including sales of refined products and rental of storage tanks, to fund our working capital requirements.  Currently we expect that these resources will be sufficient to satisfy our anticipated working capital requirements over the next 12 – 18 months.  If we cannot generate sufficient cash flows from operations, continue to make advances under the Construction and Funding Agreement or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to repayment of a loan agreement (the “Loan Agreement”) dated September 29, 2008 by and between LE and First International Bank as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000.  Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades at the Nixon Facility.  In addition, from time to time, we expect to utilize significant capital to upgrade equipment, improve facilities and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.
 
As of December 31, 2013, we were in default of certain financial covenants related to a loan agreement.   Although our lender granted a temporary waiver effective December 31, 2013 through December 31, 2014, our failure to comply with certain financial covenants in the loan agreement could materially and adversely affect our operating results and our financial condition.
 
We cannot assure that our assets or cash flow would be sufficient to fully repay borrowings under our outstanding notes payable, either upon maturity or if accelerated, or that we would be able to refinance or restructure the payments on the notes payable. If we fail to comply with covenants associated with the long-term debt and such failure is not cured or waived, then the senior lender may exercise any rights and remedies available under the loan agreement and applicable law including, without limitation, foreclosing on our assets. Any such action by our senior secured lender would have a material adverse effect on our financial condition and ability to continue as a going concern.

In June 2014, new environmental regulations become effective that reduce the allowable sulfur content for commercially sold diesel in the United States. Unless the Nixon Facility undergoes significant capital upgrades, we may be limited to selling our diesel as a distillate feedstock at lower prices.

New environmental regulations will become effective in June 2014 that reduce the sulfur content that is permitted to be contained in commercially sold diesel in the United States. In order to meet the lower sulfur content requirement for NRLM in the United States, the Nixon Facility may require capital upgrades in excess of approximately $50 million. In order to complete the required capital upgrades, we will have to finance such capital expenditures primarily through the issuance of debt and/or equity, which would result in dilution to existing stockholders and/or subject us to higher debt levels. We can continue to sell diesel with a higher sulfur content in the United States to other refineries and blenders as a feedstock and to other countries as a finished petroleum product.  There can be no assurance that we can: (i) obtain financing for capital expenditures at rates or at terms acceptable to us, if at all, (ii) sell diesel with a higher sulfur content in the United States to other refineries and blenders as feedstock or overseas as a finished product, or (iii) sell higher sulfur diesel content at prices that we deem reasonable or at all.
 
If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected.
 
Pursuant to the Energy Independence and Security Act of 2007, the EPA has promulgated the Renewable Fuel Standard, or RFS, which requires refiners to blend "renewable fuels," such as ethanol, with their petroleum fuels or purchase renewable energy credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels refineries like us are obligated to blend into their finished petroleum products increases annually over time until 2022. Beginning in February 2012, the Nixon Facility was required to blend renewable fuels into its diesel fuel or purchase RINs in lieu of blending. We submitted and lodged an application with the EPA requesting a small refinery exemption under the RFS mandate (“Hardship Exemption”) due to disproportionate economic hardship and disparate impact that compliance with the RFS mandate would have on the Nixon Facility.  There is no guarantee that the EPA will grant us the Hardship Exemption.  In addition, existing laws and/or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. If we are not granted the Hardship Exemption, we may be required to purchase additional RINs on the open market and waiver credits from the EPA in order to comply with the RFS. Recently the price of RINs has been extremely volatile with pricing increases.  We cannot predict the future prices of RINs or waiver credits, but the costs to obtain the necessary number of RINs and waiver credits could likely be material.  Additionally, because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries' product pool, potentially materially affecting our business, financial condition, results of operations, and cash flows.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.

We may incur significant liability as a result of, or costs and capital expenditures to comply with, health, safety and environmental regulations relating to the recommissioning of the Nixon Facility and/or as a result of new or modified laws and regulations.

The Nixon Facility returned to service in February 2012. We are currently undergoing a comprehensive review to determine our compliance with relevant federal, state and local environmental laws. During the course of our review, we may discover that we are not in compliance with existing environmental regulations. To the extent that we are out of compliance, we may incur significant liabilities, costs and capital expenditures to comply with such environmental regulations, which are complex and change frequently. Costs of compliance are often unpredictable, and there can be no assurance that the future costs will not be material. It is possible that we may identify additional cost in the future, which could result in additional obligations and expenses, including fines and penalties.

 
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Our refinery, pipelines and other operations are subject to federal, state and local laws regulating, 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 diesel and other matters otherwise relating to the protection of the environment. Our operations are also subject to various laws and regulations relating to occupational health and safety. Compliance with the complex array of federal, state and local laws relating to the protection of the environment, health and safety is difficult and likely will require us to make significant expenditures. Moreover, our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances into the environment including at neighboring areas or third-party storage, treatment or disposal facilities. Certain environmental laws impose joint and several liability without regard to fault or the legality of the original conduct in connection with the investigation and cleanup of such spills, discharges or releases. As such, we may be required to pay more than our fair share of such investigation or cleanup. We may not be able to operate in compliance with all applicable environmental, health and safety laws, regulations and permits at all times. Violations of applicable legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or facility shutdowns. We may also be required to make significant capital expenditures or incur increased operating costs or change operations to achieve compliance with applicable standards.

We cannot predict the extent to which additional environmental, health and safety legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, on September 12, 2012, the EPA published final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries to be effective November 13, 2012. These amendments include standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. We continue to evaluate the regulation and amended standards, as may be applicable to the operations at our refinery. We cannot currently predict costs we may incur, if any, to comply with the amended NSPS, but the costs could be material. Expenditures or costs for environmental, health and safety compliance could have a material adverse effect on our results of operations, financial condition and profitability and, as a result, our ability to make distributions.

Regulation of greenhouse gas emissions could increase our operational costs and reduce demand for our products.

Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on our operations and financial results.

International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, our activities in the particular jurisdiction and market conditions. Greenhouse gas emissions that could be regulated include those arising from the conversion of crude oil into refined petroleum products, the transportation of crude oil and natural gas, and the exploration and production of crude oil and natural gas. Some matters related to these activities, such as actions taken by our competitors in response to such laws and regulations, are beyond our control.

The effect of regulation on our financial performance will depend on a number of factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which we would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits and the impact of legislation or other regulation on our ability to recover the costs incurred through the pricing of our products. Material price increases or incentives to conserve or use alternative energy sources could also reduce demand for products we currently sell and adversely affect our sales volumes, revenues and margins.

Our primary source of crude oil supply experiences significant price swings, which impacts our crude oil acquisition cost.

The Nixon Facility is located in the heart of the Eagle Ford Shale play, an abundant source of domestic petroleum production. The gathering infrastructure in this area is developing such that, occasionally, large quantities of local crude oil may be transported in bulk away from nearby Eagle Ford Shale. When this occurs, we may experience wider than normal swings in crude oil prices in order to obtain our desired levels of crude oil.

 
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We depend exclusively on GEL for our supply of crude oil and other feedstocks, and the loss of GEL or a material decrease in the supply of crude oil and other feedstocks generally available to the Nixon Facility could have a material adverse effect on our operations and financial condition.
 
We purchase 100% of our crude oil and other feedstocks exclusively from GEL under the Crude Supply Agreement. We cannot purchase crude oil or other feedstock from another supplier without the consent of GEL. We are dependent on GEL and the loss of GEL would adversely affect our financial results to the extent we were unable to find another supplier of crude oil.
 
To the extent that GEL reduces the volumes of crude oil and other feedstocks that they supply to us as a result of declining production or competition or otherwise, our sales, net income and cash available for payments of our debt obligations would decline unless we were able to acquire comparable supplies of crude oil and other feedstocks on comparable terms from other suppliers. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We have no control over the level of drilling activity in the fields that supply the Nixon Facility, the amount of reserves underlying the wells in these fields, the rate at which production from a well will decline or the production decisions of producers. A material decrease in either crude oil production or drilling activity in the fields that supply the Nixon Facility, as a result of depressed commodity prices, natural production declines, governmental moratoriums on drilling or production activities, the availability and the cost of capital or otherwise, could result in a decline in the volume of crude oil we refine.

Loss of market share by a key customer, or consolidation among our customer base, could harm our operating results.
 
For the year ended December 31, 2013, a large percentage of our revenue, 92%, came from sales to five customers. These customers have a variety of suppliers to choose from and therefore can make substantial demands on us, including demands on product pricing and on contractual terms, which often results in the allocation of risk to us as the supplier. Our ability to maintain strong relationships with our principal customers is essential to our future performance. If we lose a key customer, if any of our key customers reduce their orders of our refined petroleum products or require us to reduce our prices before we are able to reduce costs, if a customer is acquired by one of our competitors or if a key customer suffers financial hardship, our operating results could be harmed.
 
Additionally, if there is consolidation among our customer base, our customers may be able to command increased leverage in negotiating prices and other terms of sale, which could adversely affect our profitability. In addition, if, as a result of increased leverage, customer pressures require us to reduce our pricing such that our gross margins are diminished, we could decide not to sell our refined petroleum products to a particular customer, which could result in a decrease in our revenue. Consolidation among our customer base may also lead to reduced demand for our products, replacement of our products by the combined entity with those of our competitors and cancellations of orders, each of which could harm our operating results.
 
The sale of refined petroleum products to the wholesale market is our primary business, and if we fail to maintain and grow our market share or gain market acceptance of our refined petroleum products, our operating results could suffer.

Our success in the wholesale market depends in large part on our ability to maintain and grow our image and reputation as a reliable operator and to expand into and gain market acceptance of our refined petroleum products. Adverse perceptions of product quality, whether or not justified, or allegations of product quality issues, even if false or unfounded, could tarnish our reputation and cause our wholesale customers to choose refined petroleum products offered by our competitors.

We are dependent on third parties for the transportation of crude oil into and refined petroleum products out of our Nixon Facility, and if these third parties become unavailable to us, our ability to process crude oil and sell refined petroleum products to wholesale markets could be materially and adversely affected.

We rely on trucks for the receipt of crude oil into and the sale of refined petroleum products out of our Nixon Facility. Since we do not own or operate any of these trucks, their continuing operation is not within our control. If any of the third-party trucking companies that we use, or the trucking industry in general, become unavailable to transport crude oil or our refined petroleum products because of acts of God, accidents, government regulation, terrorism or other events, our revenue and net income would be materially and adversely affected.

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

The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations. Although currently operating at anticipated levels, the Nixon Facility is still in a recommissioning phase and may require unscheduled downtime for unanticipated reasons, including maintenance and repairs, voluntary regulatory compliance measures, or cessation or suspension by regulatory authorities. Any scheduled or unscheduled downtime may result in lost margin opportunity, increased maintenance expense and a build-up of refined petroleum products inventory, which could reduce our ability to meet our payment obligations.

 
17

 
 
LEH holds a significant interest in us, and our related party transactions with LEH and its affiliates may cause conflicts of interest that may adversely affect us.

Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, and Tommy L. Byrd, our interim Chief Financial Officer, Treasurer and Assistant Secretary, are also a member and employee, respectively, of LEH and as a result may, under certain circumstances, have interests that differ from or conflict with our interests. Further, pursuant to the Management Agreement, LEH manages and operates the Nixon Facility and Blue Dolphin’s other operations. As a result of their relationship with LEH, Messrs. Carroll and Byrd may experience conflicts of interest in the execution of their duties on behalf of Blue Dolphin including with respect to the Management Agreement.

LEH owns approximately 81% of our outstanding common stock, par value $0.01 per share (the “Common Stock”). Mr. Carroll is the majority owner of LEH.  Through its ownership of such a large amount of Common Stock, LEH has significant influence over matters such as the election of our Board of Directors (the “Board”), control over our business, policies and affairs and other matters submitted to our stockholders. LEH is entitled to vote the Common Stock it owns in accordance with its interests, which may be contrary to our interests and those of other stockholders. LEH has interests that differ from the interests of our stockholders and, as a result, there is a risk that important business decisions will not be made in the best interest of some of our stockholders. LEH and its other affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities. We believe that the transactions and agreements that we have entered into with LEH and its affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties. However, these relationships could create, or appear to create, potential conflicts of interest when our Board is faced with decisions that could have different implications for us and LEH or its affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which may have a material adverse effect on our ability to do business.

The geographic concentration of our refinery and other assets creates a significant exposure to the risks of the regional economy and other regional adverse conditions. The location of our refinery also creates the risk of significantly increased transportation costs should the supply/demand balance change in our region such that regional supply exceeds regional demand for refined products.

As our refinery and other assets are located in the Eagle Ford Shale and Gulf Coast area of Texas, we primarily market our refined and retail products in a single, relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenue. These factors include, among other things, changes in the economy, weather conditions, demographics and population.
 
Should the supply/demand balance shift in our region as a result of changes in the local economy as discussed above, an increase in refining capacity or other reasons, resulting in supply in the PADD III region of the EIA exceeding demand, we would have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any. Changes in market conditions could have a material adverse effect on our business, financial condition and results of operations.

Competition from companies having greater financial and other resources than we do could materially and adversely affect our business and results of operations.

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in the PADD III region of the United States as defined by the EIA, as well as with domestic refiners in other PADD regions and foreign refiners that import products into the United States. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain all of our feedstocks from a single source. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.  If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.
 
 
18

 
 
The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities and reduce our liquidity. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our facilities, any of which could result in production and distribution difficulties and disruptions, pollution (such as oil spills, etc.), personal injury or wrongful death claims and other damage to our properties and the property of others.

There is also risk of mechanical failure and equipment shutdowns both in the normal course of operations and following unforeseen events. In such situations, undamaged refinery processing units may be dependent on, or interact with, damaged process units and, accordingly, are also subject to being shut down. Because all of our refining operations are conducted at a single refinery, any such event(s) at our refinery could significantly disrupt our production and distribution of refined products. Any sustained disruption would have a material adverse effect on our business, financial condition, results of operations and cash flows.  Additionally, our offshore operations are also subject to a variety of operating risks exclusive to the marine environment such as hurricanes or other adverse weather conditions and restrictive governmental regulation.  These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.

Genesis’ hedging of our refined petroleum products may limit our gains and expose us to other risks.

We are exposed to market price risk related to our refined petroleum products inventory. The spread between crude oil and refined product prices is the primary factor affecting our operations, liquidity and financial condition. Our crude acquisition costs and refined petroleum products sales prices depend on numerous factors beyond our control. These factors include the supply of and demand for crude oil, gasoline, NLRM and other refined petroleum products. Supply and demand for these products depend on various factors, including changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of imports and exports, marketing of competitive fuels, and government regulation.

In May 2012, we implemented an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.

Our refineries, terminals and related facility operations and other operations face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
 
Our refinery, terminals and related facility operations and other assets are subject to certain operating hazards, and our cash flow from those operations could decline if any of our facilities experiences a major accident, pipeline rupture or spill, explosion or fire, is damaged by severe weather or other natural disaster, or otherwise is forced to curtail its operations or shut down. These operating hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in significant curtailment or suspension of our related operations.

Although we maintain insurance policies, including personal and property damage and business interruption insurance for each of our facilities with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent, we cannot ensure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or significant interruption of operations. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. In addition, we are not fully insured against all risks incident to our business because certain risks are not fully insurable, coverage is unavailable or premium costs, in our judgment, do not justify such expenditures. For example, we are not insured for environmental accidents at all of our facilities.

 
19

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

The success of our business operations depends largely upon the efforts of key executive officers and technical personnel. Given our small size, we may not be able to retain required personnel on acceptable terms due to the competition for experienced personnel from other companies in the industry.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.
 
ITEM 2.  PROPERTIES

Owned and Leased Assets

We own, lease, and have leasehold interests in the properties listed below:

Property
 
Business Segment(s)
 
Acres
 
Owned / Leased
 
Location
                   
Nixon  Facility
 
Refinery Operations
 
56
   
Owned
 
Nixon, Wilson County, Texas
Freeport Facility
 
Pipeline Transportation
 
193
   
Owned
 
Freeport, Brazoria County, Texas
Offshore Pipelines
 
Pipeline Transportation
 
--
   
Owned
 
U.S. Gulf of Mexico
Oil and Gas Properties
 
Exploration and Production
 
--
   
Leasehold Interest
 
U.S. Gulf of Mexico
Corporate Headquarters
 
Corporate and Other
 
--
   
Lease
 
Houston, Harris County, Texas

  
Nixon Facility – Located in Nixon, Wilson County, Texas, the Nixon Facility is a 56 acre crude oil and condensate processing facility that has a current operating capacity of approximately 15,000 bpd. The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, jet fuel treater, approximately 120,000 bbls of crude oil storage capacity, approximately 148,000 bbls of refined product storage capacity and related loading and unloading facilities and utilities. The Nixon Facility is pledged as collateral under a Security Agreement as discussed in Part II, Item 8 “Financial Statements and Supplementary Data – Note (15) Long-Term Debt” of this report.

  
Freeport Facility – Located in Freeport, Brazoria County, Texas, the Freeport Facility encompasses approximately 193 acres of land and includes pipeline easements and right-of-ways, crude oil and natural gas separation and dehydration facilities, a vapor recovery unit and two onshore pipelines.  The two onshore pipelines consist of approximately 4 miles of the 20-inch Blue Dolphin Pipeline and a 16-inch natural gas pipeline that connects the Freeport Facility to the Dow Chemical Plan Complex in Freeport, Texas.

  
Offshore Pipelines –The following provides a summary of our offshore pipelines, all of which are located in the U.S. Gulf of Mexico:
 
               
Natural Gas
               
Capacity
 
Pipeline
 
Location
 
Ownership
 
Miles
 
(MMcf/d)
 
                   
Blue Dolphin Pipeline(1)
U.S. Gulf of Mexico
 
100%
 
38
 
160
 
GA 350 Pipeline
 
U.S. Gulf of Mexico
 
100%
 
13
 
65
 
Omega Pipeline(2)
 
U.S. Gulf of Mexico
 
100%
 
18
 
110
 
__________________________________________
(1)  
Currently inactive.
(2)  
Currently abandoned in place.
 
 
 
20

 
 
 
o  
Blue Dolphin Pipeline System (“Blue Dolphin Pipeline”) – The Blue Dolphin Pipeline consists of 16-inch and 20-inch pipeline segments, including a trunk line and lateral lines, that span approximately 38 miles and run from an offshore anchor platform in Galveston Area Block 288 to our Freeport Facility.  The Blue Dolphin Pipeline has an aggregate capacity of approximately 180 MMcf of gas and 7,000 Bbls of crude oil and condensate per day;

o  
Galveston Area Block 350 Pipeline (the “GA 350 Pipeline”) – The GA 350 Pipeline is an 8-inch, 13 mile offshore pipeline extending from Galveston Area Block 350 to a subsea interconnect and tie-in with a transmission pipeline in Galveston Area Block 391.  The GA-350 Pipeline has a capacity of approximately 65 MMcf of gas per day; and

o  
Omega Pipeline (the “Omega Pipeline”) – The Omega Pipeline is a 12-inch, 18 mile offshore pipeline that originates in the High Island Area, East Addition Block A-173 and extends to West Cameron Block 342, where it was previously connected to the High Island Offshore System. The Omega Pipeline was abandoned in place in 1997.  Reactivation of the Omega Pipeline is dependent upon future drilling activity in its vicinity and the successful attraction of producer/shippers to the system. When it was active, the Omega Pipeline had a capacity of approximately 110 MMcf of gas per day.

  
Oil and Gas Properties – Oil and gas properties include a 2.5% working interest and 2.008% net revenue interest in High Island Block 115, a 0.5% overriding royalty interest in Galveston Area Block 321, and a 2.88% working interest and 2.246% net revenue interest in High Island Block 37.  All of the leases associated with these oil and gas properties have expired.

  
Corporate Headquarters – We lease 6,489 square feet of office space in Houston, Harris County, Texas, which serves as our company headquarters.  Our office lease is discussed more fully in Part II, Item 8 “Financial Statements and Supplementary Data – Note (19) Leases” included in this Annual Report on Form 10-K.

LEH manages and operates all of our properties and is reimbursed for their management and operation under the Management Agreement.  We believe that our properties are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business.

Options to Purchase Assets

  
 LTRI Option -- In June 2012, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Texas Refinery I, LLC (“LTRI”), a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.  The LTRI Option expired on December 31, 2013; however, the parties are in discussions related to the terms for extending the option.  Although the contemplated transaction is with a related party, the Board has determined that the contemplated transaction is advisable, fair to and in the best interests of our stockholders.

In the event we exercise the option to purchase the Ingleside Refinery, Blue Dolphin and LEH will enter into a definitive purchase and sale agreement. We paid LEH a fully refundable sum of $100,000 in cash as consideration to purchase the exclusive option.  Upon exercise of the exclusive option to purchase the Ingleside Refinery, we will assume all outstanding liabilities, including a note payable, and reimburse LEH for costs associated with the acquisition, refurbishment and environmental remediation of the site.  The parties continue to monitor such refurbishment and remediation efforts as a prerequisite to determining the purchase price. If there is a material difference between LEH’s expenditures for such remediation efforts and our desired purchase price, LEH has agreed to refund us the purchase price for the Ingleside Refinery option.

  
 LED OptionIn connection with the LE Acquisition, we purchased an exclusive option from LEH to acquire all of the issued and outstanding membership interests of Lazarus Energy Development, LLC (“LED”), a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option. The LED Option expired on December 31, 2013; however, the parties are in discussions related to the terms for extending the option. Although the contemplated transaction is with a related party, the Board has determined that the contemplated transaction is advisable, fair to and in the best interests of our stockholders.


 
21

 
 
ITEM 3.  LEGAL PROCEEDINGS

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

 
ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.


 

 









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22

 
 
PART II

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

Market Information

Simultaneous with the delisting of our Common Stock from the Nasdaq Capital Market on February 28, 2012, our Common Stock began trading on the OTCQX U.S. Premier tier of the OTC Markets under the ticker symbol “BDCO."  The following table sets forth, for the periods indicated, the high and low prices for our Common Stock as reported by the NASDAQ and the OTC Markets.  The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.
 
 
 Quarter Ended   High     Low  
             
2013
             
December 31   $ 6.90     $ 4.15  
September 30   $ 7.00     $ 5.01  
June 30   $ 6.49     $ 5.12  
March 31   $ 9.97     5.00  
                 
2012                
December 31   $ 6.50     $ 3.85  
September 30   $ 7.95     $ 6.01  
June 30   $ 9.22     $ 6.18  
March 31   $ 11.60     $ 4.28  
 
Holders

As of March 31, 2014, we had approximately 280 record holders of our Common Stock. We have approximately 3,000 beneficial holders of our Common Stock.

Dividends

We have not declared or paid any dividends on our Common Stock since our incorporation.  We currently intend to retain earnings for our capital needs and expansion of our business and do not anticipate paying cash dividends on the Common Stock in the foreseeable future. We expect that any loan agreements we enter into in the future will likely contain restrictions on the payment of dividends on our Common Stock. Future policy with respect to dividends will be determined by the Board based upon our earnings and financial condition, capital requirements and other considerations.

ITEM 6.  SELECTED FINANCIAL DATA

Not applicable.
 
                                                                    
 
23

 
 
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is a review of certain aspects of our financial condition and results of operations and should be read in conjunction with “Part I, Item 1. Business” and “Part II, Item 8. Financial Statements and Supplementary Data” including the associated “Notes to Consolidated Financial Statements” of this report.

Executive Summary

Our primary business is the refining of crude oil and condensate into marketable finished and intermediate products at the Nixon Facility, which is a crude oil and condensate processing facility with a current operating capacity of approximately 15,000 barrels (“bbls”) per day (“bpd”). The Nixon Facility is located on a 56 acre site in Nixon, Wilson County, Texas, and consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, jet fuel treater, approximately 120,000 bbls of crude oil storage capacity, approximately 148,000 bbls of refined product storage capacity and related loading and unloading facilities and utilities.  As part of our refinery business segment we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refinery Operations Business Strategy

We are dedicated to maintaining safe, efficient and reliable refinery operations, improving liquidity and profitability, and focusing on safety and environmental stewardship.   Throughout 2013, we took a number of steps to more effectively operate the Nixon Facility and manage the spread between our cost to acquire crude oil and the price of the refined petroleum products that we ultimately sell, as follows:
 
  
Safety and Environmental Management – We implemented programs and procedures across the company for managing safety and environmental matters with a focus on the assignment of responsibilities, sound risk management and decision-making, efficient and cost-effective planning and operations and regulatory compliance.  We also completed an assessment of process safety management (“PSM”) standards at the Nixon Facility.  Improving our PSM standards and developing a PSM program at the Nixon Facility, which is designed to address all aspects of OSHA guidelines for developing and maintaining a comprehensive PSM program, is an integral part of our safety and environmental management strategy going forward;
 
  
Improved Product Mix – The Nixon Facility began producing jet fuel – the Nixon Facility’s fifth commercially saleable product – in mid-September 2013.  Jet fuel is produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream.  Production of jet fuel, which is considered a higher value product, significantly upgrades the value of the naphtha component.  We plan to significantly increase the production of jet fuel during 2014;

  
Naphtha Stabilizer and Depropanizer Units Refurbishment – We continued the refurbishment of certain components of the Nixon Facility, including the naphtha stabilizer and depropanizer units at the Nixon Facility, which we anticipate will: (i) improve the overall quality of the naphtha that we produce, (ii) allow higher recovery of lighter products that can be sold as a liquefied petroleum gas (“LPG”) mix, and (iii) increase the amount of throughput that can be processed by the Nixon Facility.  The estimated cost to refurbish the naphtha stabilizer and depropanizer units is approximately $1.5 million; and

  
Nixon Facility Improvements – We continued to enhance our condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, such as installing new laboratory equipment and a new caustic system and upgrading loading bay meters.





Remainder of Page Intentionally Left Blank
 
 
 
24

 
 
Key Operating Statistics

Key operational statistics for our core business segment, refinery operations, were as follows:
 
       
   
Year Ended December 31,
 
   
2013
   
2012
 
             
Operating days
    341       326  
                 
Total refinery throughput(1)
               
bbls
    3,822,128       3,176,530  
bpd
    11,209       9,744  
Capacity utilization rate
    75 %     65 %
                 
Total refinery production
               
bbls
    3,743,482       3,116,650  
bpd
    10,978       9,560  
Capacity utilization rate
    73 %     64 %
_________________________________________________
(1)  
Total refinery throughput includes crude oil and condensate and other feedstocks.
 
Major Influences on Results of Operations

The safe, efficient and reliable operation of the Nixon Facility is critical to our financial performance.  Any adverse financial impact of a maintenance turnaround or significant capital improvement project is mitigated through a diligent planning process that considers expectations for product availability, seasonality, margin environment and the availability of resources to perform the required work.  Periodic maintenance and repairs are generally performed annually, depending on the processing units involved.
 
Earnings and cash flow from our refining operations are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined petroleum products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products, which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of imports, marketing of competitive fuels and government regulation.

We monitor our per barrel refinery operating margins in order to measure our operating performance. We calculate the per barrel operating margin for the Nixon Facility by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (excluding any substantial unrealized hedge positions and certain inventory adjustments).
 
The Nixon Facility is capable of processing substantial volumes of low-sulfur crude oil (sweet crude) and condensate to produce a high percentage of light, higher valued refined petroleum products. Sweet crude and condensate derived from surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s input.
 
The nature of our business requires us to maintain access to substantial quantities of crude oil and refined product inventories. Crude oil and refined petroleum products are essentially commodities, and we have no control over the changing market value of these inventories. We utilize an inventory risk management policy in which derivative instruments may be used as economic hedges to reduce our crude oil and refined petroleum products inventory commodity price risk.

 
25

 
 
Relationship with Genesis

We continue to be dependent on our relationship with Genesis and its affiliates.  Our relationship with Genesis is governed by three agreements:

the Crude Oil Supply and Throughput Services Agreement by and between GEL and LE dated August 12, 2011 (the “Crude Supply Agreement”);
 
the Construction and Funding Contract by and between LE and Milam, an affiliate of Genesis, dated August 12, 2011 (the “Construction and Funding Agreement”); and
 
the Joint Marketing Agreement by and between GEL and LE dated August 12, 2011 (as subsequently amended, the “Joint Marketing Agreement”).
 
Below is a discussion of the material terms and conditions of each of our agreements with Genesis.
 
Crude Supply Agreement.  Pursuant to the Crude Supply Agreement, GEL, an affiliate of Genesis, is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.
  
Construction and Funding Agreement.  Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam has continued to make advances in excess of their obligation, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.
 
The Construction and Funding Agreement places restrictions on LE, which prohibit LE from:  (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.
 
In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility.  All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement will constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.
 
Joint Marketing Agreement.  The Joint Marketing Agreement sets forth the terms of the agreement between LE and GEL pursuant to which the parties will market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil pursuant to the Crude Supply Agreement) as follows:
 
 
 
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(a)
First, prior to the date on which Milam has recouped all amounts advanced to LE under the Construction and Funding Agreement (the “Investment Threshold Date”), the Base Construction Payment of $150,000 shall be paid to GEL (for remittance to Milam) each calendar month to satisfy amounts owed under the Construction and Funding Agreement, with a catch-up in subsequent months if there is a Deficit Amount until such Deficit Amount has been satisfied in full.
  
(b)
Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any Accounting Fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.
 
(c)
Third, prior to the Investment Threshold Date and subject to the payment of the Base Construction Payment by LE and the Operations Payments by GEL, pursuant to (a) and (b) above, an amount shall be paid to GEL from Gross Profits equal to transportation costs, tank storage fees (if applicable), financial statement preparation fees (collectively, the “GEL Expense Items”), after which GEL shall be paid 80% of the remaining Gross Profits (any percentage of Gross Profits distributed to GEL, the “GEL Profit Share”) and LE shall be paid 20% of the remaining Gross Profits (any percentage of Gross Profits distributed to LE, the “LE Profit Share”); provided, however, that in the event that there is a forbearance payment of Gross Profits required by LE under a forbearance agreement with a bank, then 50% of the LE Profit Share shall be directly remitted by GEL to the bank on LE’s behalf until such forbearance amount is paid in full; and provided further that, if there is a Deficit Amount due under the Construction and Funding Agreement and a forbearance payment of Gross Profits that would otherwise be due and payable to the bank for such period, then GEL shall receive 80% of the Gross Profit and 10% shall be payable to the bank and LE shall not receive any of the LE Profit Share until such time as the Deficit Amount is reduced to zero.
   
(d)
Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.
 
(e)
After the Investment Threshold Date, if GEL sustains losses, it can recoup those losses 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.
 
The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances.  For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above.  The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014.  In accordance with the terms of the October 2013 Letter Agreement, LE 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 12, 2019 unless sooner terminated by GEL with 180 days prior written notice.
  
Amendments and Clarifications to the Joint Marketing Agreement.  The Joint Marketing Agreement was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.
 
(a)
In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our obligation amount under the Construction and Funding Agreement. In addition, the parties agreed to amend the priority of payments to reflect that, to the extent that there are available funds in a particular month, AFNB shall be paid one-tenth of such funds, provided that we will not participate in available funds until Deficit Amounts added to the Construction and Funding Agreement are paid in full.
 
 
 
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(b)
In December 2012, GEL made Operations Payments and other payments to or on behalf of LE in which the aggregate amount exceeded the amount payable to LE in the month of December 2012 under the Joint Marketing Agreement (the “Overpayment Amount”). In December 2012, we entered into an amendment to the Joint Marketing Agreement whereby GEL and Milam agreed that Gross Profits payable to LE would be redirected to GEL as payment for the Overpayment Amount until such Overpayment Amount has been satisfied in full. Such redistributions shall not reduce the distributions of Gross Profit that GEL or Milam are otherwise entitled to under the Joint Marketing Agreement.
 
(c)
In February 2013, Milam paid a vendor $64,358 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees.  In addition, Milam and GEL incurred legal fees and expenses related to settling the matter.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.
 
(d)
In February 2013, GEL agreed to advance to LE the funds necessary to pay for the actual costs incurred for the scheduled maintenance turnaround at the Nixon Facility and capital expenditures relating to an electronic product meter, lab equipment and certain piping in an amount equal to the actual costs of the refinery turnaround and capital expenditures, not to exceed $840,000 in the aggregate.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed that all amounts advanced by GEL or its affiliates to LE pursuant to the letter agreement shall constitute obligations under the Construction and Funding Agreement.
 
As of December 31, 2013, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,747,330.  As of December 31, 2013, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount included in our obligation amount under the Construction and Funding Agreement was $2,538,077.
 
Results of Operations

Year Ended December 31, 2013 (the "Current Year") Compared to Year Ended December 31, 2012 (the "Prior Year").
 
The Nixon Facility was refurbished and began operations in February 2012.  The Nixon Facility operated for a total of 341 days at 75% of operating capacity during the Current Year. The Nixon Facility operated for a total of 326 days at 65% of operating capacity during the Prior Year.

Summary. For the Current Year we reported a loss from continuing operations, net of tax, of $3,807,129, or a loss of $0.36 per share, compared to a loss from continuing operations, net of tax, of $13,841,066, or a loss of $1.35 per share, for the Prior Year.  We reported a loss from discontinued operations of $4,443,566, or a loss of $0.43 per share, in the Prior Year compared to no loss from discontinued operations in the Current Year.   The loss from continuing operations, net of tax, in the Current Year was primarily attributable to lower refining margins.  The Nixon Facility, which was returned to service in February 2012, operated for 15 more days and had an increase in total refinery throughput of approximately 10% in the Current Year compared to the Prior Year.  However, for the same period: (i) the average price per barrel of crude oil was higher, (ii) the average sales price per barrel of our refined products sold was lower, and (iii) the Nixon Facility was operating less than optimally.  During the Current Year, we adopted a condition-based predictive maintenance turnaround policy and completed several smaller capital improvement projects at the Nixon Facility, including installing new laboratory equipment and a new caustic system and updating the meters at the loading bays, to improve the operating efficiency of the Nixon Facility.  We will continue to make facility improvements to further optimize capacity utilization rates and improve product yields.

The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations.  Downtime may result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations.  The Nixon Facility experienced 25 calendar days of downtime in the Current Year.  During the first quarter of the Current Year, the Nixon Facility experienced 14 calendar days of scheduled downtime for a planned maintenance turnaround.  During the fourth quarter of the Current Year, the Nixon Facility experienced 9 calendar days of unscheduled downtime for maintenance and a review, at management’s voluntarily election, of compliance with regulatory record keeping requirements.  The Nixon Facility experienced 40 calendar days of scheduled and unscheduled downtime in the Prior Year related start-up maintenance.  See “Part I, Item 1A. Risk Factors” in in this report for risk factors related to Nixon Facility downtime.

 
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Total Revenue from Operations. For the Current Year we had total revenue from operations of $409,543,069 compared to total revenue from operations of $352,094,714 for the Prior Year.   The increase in total revenue from operations was primarily the result of operating 15 more days and increased throughput at the Nixon Facility in the Current Year compared to the Prior Year.  Substantially all of our revenue in the Current Year came from refined product sales, which generated revenue of $409,239,747, or more than 99% of total revenue from operations, compared to $351,665,234, or more than 99% of total revenue from operations, in the Prior Year.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $399,101,182 for the Current Year compared to $342,035,755 for the Prior Year.  The increase in cost of refined products sold was primarily the result of operating 15 more days and increased throughput at the Nixon Facility in the Current Year compared to the Prior Year.

Refinery Operating Expenses. We recorded refinery operating expenses of $10,673,722 in the Current Year, all of which were for services provided to us by LEH to manage and operate Blue Dolphin’s assets pursuant to the Management Agreement with LEH.  For the Prior Year, we recorded refinery operating expenses of $8,603,155.  See “Part I, Item 1. Financial Statements - Note (11), Accounts Payable, Related Party” of this report for additional disclosures related to the Management Agreement.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $163,163 in the Current Year compared to $391,169 in the Prior Year.  The decline in pipeline operating expenses was the result of lower throughput on our pipeline systems.

Lease Operating Expenses. Lease operating expenses totaled $67,923 in the Current Year compared to $57,122 in the Prior Year.

General and Administrative Expenses. We incurred general and administrative expenses of $1,794,053 in the Current Year compared to $2,076,946 in the Prior Year.  The decrease in general and administrative expenses in the Current Year was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $1,342,563 in the Current Year compared to $1,622,864 in the Prior Year.  We recorded a significant impairment to our pipeline and oil and gas assets in 2012, which reduced the carrying value of these assets and resulted in a corresponding decrease in depletion, depreciation and amortization expense.

Abandonment Expense. We recognized $63,767 of abandonment expense in the Current Year compared to $1,184,549 in the Prior Year.  Abandonment expense in the Prior Year primarily related to plugging and abandonment costs associated with our High Island A-7 oil and gas property.  We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 

Impairment. Due to the continued weakness in our pipeline transportation and oil and gas exploration production business segments and the uncertainty of the timing and speed of recovery, we recorded an impairment of $9,435,745 in the Prior Year. The impairment charge in the Prior Year consisted of $7,990,025 related to our pipeline fixed assets and $1,445,720 related to goodwill, 100% of which was associated with our pipeline transportation and oil and gas exploration production business segments. We recorded $0 in impairment charges in the Current Year. See “Intangibles – Goodwill and Other” and “Recently Adopted Accounting Guidance” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information related to goodwill, other intangible assets, impairment of goodwill and impairment of long-lived assets.

Other Income. We recognized $1,155,064 in net tank rental revenue in the Current Year compared to $534,047 in the Prior Year.  The increase in net tank rental revenue was primarily a result of additional tanks being leased to customers.

Discontinued Operations, Net of Tax.  We reported a loss from discontinued operations, net of tax, of $4,443,566 in the Prior Year compared to $0 in the Current Year.  On November 6, 2012, BDEX entered into a Sale and Purchase Agreement with Blue Sky to dispose of its 7% undivided working interest in Indonesia.  As a result, our operations related to Indonesia ceased effective November 6, 2012 and the disposal was completed on February 28, 2013.

 
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Earnings Before Interest, Income Taxes and Depreciation (“EBITDA”)

Management uses EBITDA, a non-GAAP financial measure, to assess the operating results and effectiveness of our business segments, which consist of our consolidated businesses and investments. We believe EBITDA is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by management. EBITDA is adjusted for: (i) items that do not impact our income or loss from continuing operations, such as the impact of accounting changes, (ii) income taxes and (iii) interest income (expense), depreciation and amortization. We exclude interest expense (or income) and other expenses or income not pertaining to the operations of our segments from this measure so that investors may evaluate our current operating results without regard to our financing methods or capital structure. We understand that EBITDA may not be comparable to measurements used by other companies. Additionally, EBITDA should be considered in conjunction with net income (loss) and other performance measures such as operating cash flows.

Following is a reconciliation of EBITDA by business segment for the year ended December 31, 2013 (and at December 31, 2013) and the year ended December 31, 2012 (and at December 31, 2012):
 
   
Year Ended December 31, 2013
 
   
Segment
             
               
Oil and Gas
             
   
Refinery
   
Pipeline
   
Exploration &
   
Corporate
       
   
Operations
   
Transportation
   
Production
   
and Other
   
Total
 
Revenue
  $ 409,239,747     $ 303,122     $ 200     $ -     $ 409,543,069  
Operation cost(1)
    (409,800,285 )     (377,245 )     (146,806 )     (1,652,160 )     (411,976,496 )
Other non-interest income
    1,113,397       41,667       -       -       1,155,064  
EBITDA
  $ 552,859     $ (32,456 )   $ (146,606 )   $ (1,652,160 )   $ (1,278,363 )
                                         
Depletion, depreciation and amortization
                                    (1,342,563 )
Other expense, net
                                    (1,096,948 )
                                         
Loss from continuing operations,
                                       
before income taxes
                                  $ (3,717,874 )
                                         
Capital expenditures
  $ 1,477,729     $ -     $ -     $ -     $ 1,477,729  
                                         
Identifiable assets(2)
  $ 54,470,723     $ 2,378,806     $ 20,661     $ 809,311     $ 57,679,501  
                                         
_____________________________________________
 
  (1) 
Within operation cost, general and administrative expenses are allocated across business segments based on revenue. General and administrative expenses associated with corporate maintenance costs (such as director fees and legal expenses) are included in the Corporate and Other business segment. The effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations business segment. Cost of refined products sold includes a realized loss of $246,210 and an unrealized gain of $143,050.
  (2) 
Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.
 
Remainder of Page Intentionally Left Blank

 
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Year Ended December 31, 2012
 
   
Segment
             
               
Oil and Gas
             
   
Refinery
   
Pipeline
   
Exploration &
   
Corporate
       
   
Operations
   
Transportation
   
Production
   
and Other
   
Total
 
Revenues
  $ 351,665,234     $ 406,812     $ 22,668     $ -     $ 352,094,714  
Operation cost(1)
    (350,940,269 )     (8,676,242 )     (2,018,126 )     (2,270,009 )     (363,904,646 )
Other non-interest income
    534,047       -       -       -       534,047  
EBITDA
  $ 1,259,012     $ (8,269,430 )   $ (1,995,458 )   $ (2,270,009 )   $ (11,275,885 )
                                         
Depletion, depreciation and amortization
                                    (1,622,864 )
Other expense, net
                                    (932,639 )
                                         
Loss from continuing operations,
                                       
before income taxes
                                  $ (13,831,388 )
                                         
Loss from discontinued operations
                                  $ (4,443,566 )
                                         
Capital expenditures
  $ 2,852,460     $ -     $ -     $ -     $ 2,852,460  
                                         
Identifiable assets(2)
  $ 52,745,767     $ 1,861,055     $ 48,247     $ 1,726,857     $ 56,381,926  
                                         
____________________________________
 
  (1) 
Within operation cost, general and administrative expenses are allocated across business segments based on revenue. General and administrative expenses associated with corporate maintenance costs (such as director fees and legal expenses) are included in the Corporate and Other business segment. The effect of economic hedges on our refined petroleum products and crude oil inventory, which are executed by Genesis, is included within the operation cost of our Refinery Operations business segment. Cost of refined products sold includes a realized loss of $90,507 and an unrealized loss of $136,100.  Impairment expenses of $7,990,025 related to our pipeline fixed assets and $1,445,720 related to goodwill are included within the operation cost of our Pipeline Transportation and Corporate and Other business segments, respectively.
  (2) 
Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and payable and recorded net assets.
 
Critical Accounting Policies

Long Lived Assets.
 
Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are included in the Management Agreement and covered by LEH (see “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Accounts Payable, Related Party” in this report for additional disclosures related to the Management Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.
 
Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations.
 
For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service.
 
Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. 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 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 did not record any impairment of our refinery and facilities for the years ended December 31, 2013 and 2012.
 
 
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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 U.S. Gulf of Mexico oil and gas properties were uneconomical for the years ended December 31, 2013 and 2012 due to leases being relinquished and fields being shut-in by operators. We disposed of our operations in Indonesia in 2012.
 
Pipelines and Facilities Assets. Pipelines and facilities assets have historically been recorded at cost. Following the impairment of our pipeline fixed assets in 2012, we record pipelines and facilities assets at the lower of cost or net realizable value. 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, 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 related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service.
 
Goodwill. We recognized goodwill in connection with our reverse merger with LE in 2012. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition and is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with FASB ASC guidance related to intangibles, goodwill and other. We perform an impairment test annually in the fourth quarter.
 
Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.
 
In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment.” Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.
 
The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.
 
The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill during the fourth quarter of 2012. The impairment recognized during 2012 represented 100% of goodwill.
 
Other Intangible Assets. We recognized trade name in connection with our reverse merger with LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2013.
 
 
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Revenue Recognition. We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil. Revenue from refined product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.
 
Customers assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.
 
Revenue from tank storage rental is recorded monthly in accordance with the terms of the related lease agreement. The lessee is invoiced monthly for the amount of rent due for the related period.
 
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. 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 date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques.
 
We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating or disposing of our offshore platform, pipeline systems and related onshore facilities, as well as plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.
 
Recently Adopted Accounting Guidance

The guidance issued by the FASB during the year ended December 31, 2013 is not expected to have a material effect on our consolidated financial statements.









Remainder of Page Intentionally Left Blank
 
 
 
33

 

 
Liquidity and Capital Resources

Sources and Uses of Cash.
 
   
Three Months Ended December 31,
   
Year Ended December 31,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Cash flow from operations
                       
Adjusted loss from continuing operations
  $ 4,691,841     $ 2,736,327     $ (2,287,900 )   $ (1,831,753 )
Adjusted loss from discontinued operations
    -       (435,460 )     -       (435,460 )
Change in assets and current liabilities
    892,524       811,739       3,311,718       2,334,540  
                                 
Total cash flow from operations
    5,584,365       3,112,606       1,023,818       67,327  
                                 
Cash inflows (outflows)
                               
Proceeds from issuance of debt
    -       (2,563,062 )     5,750,611       4,788,623  
Payments on long term debt
    (5,213,230 )     -       (5,274,106 )     (3,276,748 )
Cash acquired on Acquisition
    -       115       -       1,674,709  
Capital expenditures
    (232,870 )     (284,011 )     (1,477,729 )     (2,852,460 )
Proceeds from sale of assets
    -       -       201,000       -  
Proceeds from notes payable
    -       -       15,032       24,548  
Payments on note payble
    (18,360 )     (4,025 )     (224,805 )     (26,925 )
Proceeds from exercise of stock options
    -       20,000       -       20,000  
                                 
Total cash inflows (outflows)
    (5,464,460 )     (2,830,983 )     (1,009,997 )     351,747  
                                 
Total change in cash flows
  $ 119,905     $ 281,623     $ 13,821     $ 419,074  
 
At December 31, 2013, our available cash was $434,717.  We are currently relying on our profit share, GEL and LEH to fund our working capital requirements. During months in which we receive no profit share distribution, GEL and/or LEH may, but are not required to, fund our operating losses. As of December 31, 2013, the Deficit Amount financed by GEL was $2,538,077 and the working capital amount funded by LEH was $3,659,340.  For months in which GEL finances Deficit Amounts, LE does not receive any of its profit share until the Deficit Amounts have been repaid.

We believe that our aforementioned operational strategy will be sufficient to support our operations over the next 12 months.  (See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operational Strategy” of this report for disclosures related to our operational strategy.) However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes, or that GEL and/or LEH will continue to fund our working capital requirements during months in which we have operational losses.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.  See “Part I, Item 1A. Risk Factors” in in this report for risk factors related to working capital, liquidity and Nixon Facility downtime.

For the Current Year, we experienced positive cash flow from operations of $1,023,818.  For the Prior Year, we experienced positive cash flow from operations of $67,327. This represented an increase in cash flow from operations of $956,491 for the Current Year compared to the Prior Year.  For the three months ended December 31, 2013, we experienced positive cash flow from operations of $5,584,365.  For the three months ended December 31, 2012, we experienced positive cash flow from operations of $3,112,606. This represented an increase in cash flow from operations of $2,471,759 for the three months ended December 31, 2013 compared to the same period a year earlier.

We continue to work with our vendors to bring our outstanding accounts payable current as expeditiously as possible. In the event that our efforts are not successful, we will experience a significant and material adverse effect on our continuing operations, liquidity and financial condition.
 
Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the years ended December 31, 2013 and 2012 as a result of leases being relinquished and fields being shut-in by operators. On February 28, 2013 Blue Dolphin Exploration Company (“BDEX”), a wholly owned subsidiary, completed the disposal of its 7% undivided working interest in the North Sumatra Basis – Langsa Field offshore Indonesia (“Indonesia”) pursuant to Sale and Purchase Agreement with Blue Sky Langsa Limited (“Blue Sky”) effective November 6, 2012.

We recognized $63,767 of abandonment expense in the Current Year related to our High Island A-7 and High Island 37 oil and gas properties.  For the Prior Year, plugging and abandonment costs related to our High Island A-7 oil and gas property exceeded the amount reserved for the ARO liability.  Accordingly, the excess amount, which was $1,184,549, was recognized as a loss in the Prior Year.   We will record additional plugging and abandonment costs for oil and gas properties as information becomes available from operators to substantiate actual and/or probable costs. 
 
 
 
34

 

Capital expenditures in the Current Year and Prior Year totaled $1,477,729 and $2,852,460, respectively, which related to investments in the Nixon Facility and $592,415 of asset retirement obligations incurred in a non-cash transaction.  Capital expenditures in the three month periods ended December 31, 2013 and 2012 totaled $232,870 and $284,011, respectively, which related to investments in the Nixon Facility.  We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $5,747,330 and $5,206,175, including Deficit Amounts, at December 31, 2013 and 2012, respectively.

The principal balance outstanding on the Refinery Note was $9,057,937 and $9,298,183 at December 31, 2013 and 2012, respectively. On June 1, 2013, AFNB and LE agreed to amend the Refinery Note (the “Note Modification Agreement”).  Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310.

The principal balance outstanding on the Notre Dame Debt was $1,300,000 at December 31, 2013 and 2012. There are no financial covenants associated with this debt.

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (15) Long-Term Debt” of this report for additional disclosures related to our long-term debt obligations.
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk. We are exposed to market price risk related to our refined petroleum products and crude oil inventory. The spread between crude oil and refined product prices is the primary factor affecting our operations, liquidity and financial condition. Our crude acquisition costs and refined petroleum products sales prices depend on numerous factors beyond our control. These factors include the supply of and demand for crude oil, gasoline, NRLM and other refined petroleum products. Supply and demand for these products depend, among other things, on changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; production levels; availability of imports and exports; marketing of competitive fuels; and government regulation.

In May 2012, we implemented an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products and crude oil inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.
 
At December 31, 2013, we performed a sensitivity analysis to determine the impact of an increase in the market price of commodity contracts for our economic hedges. Based on this sensitivity analysis, we determined that an increase of $1.00 per barrel in commodity contracts held at December 31, 2013 would increase unrealized loss by approximately $45,000.

Interest Rate Risk. We are exposed to interest rate volatility with regard to existing variable rate debt tied to movements in the U.S. prime rate. At December 31, 2013, we had $9,057,937 of variable interest debt with a weighted average interest rate at year end of approximately 5.50%. At December 31, 2013, we performed a sensitivity analysis to determine the impact of an increase in interest rates. Based on this sensitivity analysis, we determined that an increase of 1% in our average floating interest rates at December 31, 2013 would increase interest expense by approximately $90,579 per year.
 
 
 
35

 
 


 
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Index to Financial Statements
 
 
 
Report of Independent Registered Public Accounting Firm 37
   
Consolidated Balance Sheets at December 31, 2013 and 2012
38
   
Consolidated Statements of Operations for the Years Ended December 31, 2013 and 2012
 39
   
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2013 and 2012
 40
   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013 and 2012
 41
   
Notes to Consolidated Financial Statements
42
 
 
 



Remainder of Page Intentionally Left Blank
 
 
 
36

 


 
Report of Independent Registered Public Accounting Firm


The Board of Directors and
Stockholders of Blue Dolphin Energy Company
 
We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and its subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and its subsidiaries as of December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ UHY LLP
Sterling Heights, Michigan
March 31, 2014
 
 
 
37

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Balance Sheets
 
 
     December 31,  
     2013      2012  
 ASSETS
           
 CURRENT ASSETS
           
 Cash and cash equivalents
  $ 434,717     $ 420,896  
 Restricted cash
    327,388       89,593  
 Accounts receivable
    13,487,106       15,398,755  
 Prepaid expenses and other current assets
    333,683       228,314  
 Deposits
    1,219,660       1,236,447  
 Inventory
    4,686,399       2,300,692  
     Total current assets
    20,488,953       19,674,697  
                 
 Total property and equipment, net
    36,388,666       35,862,085  
 Debt issue costs, net
    498,536       532,335  
 Other assets
    -       9,463  
 Trade name
    303,346       303,346  
 TOTAL ASSETS
  $ 57,679,501     $ 56,381,926  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 CURRENT LIABILITIES
               
 Accounts payable
  $ 20,783,541     $ 19,171,013  
 Accounts payable, related party
    3,659,340       1,594,021  
 Notes payable
    11,884       43,941  
 Asset retirement obligations, current portion
    107,388       -  
 Accrued expenses and other current liabilities
    1,600,444       725,238  
 Interest payable, current portion
    40,272       640,352  
 Long-term debt, current portion
    2,215,918       1,816,960  
     Total current liabilities
    28,418,787       23,991,525  
                 
 Long-term liabilities:
               
 Asset retirement obligations, net of current portion
    1,490,273       921,260  
 Long-term debt, net of current portion
    13,889,349       13,989,517  
 Long-term interest payable, net of current portion
    1,767,381       858,784  
 Total long-term liabilities
    17,147,003       15,769,561  
                 
 TOTAL LIABILITIES
    45,565,790       39,761,086  
                 
 STOCKHOLDERS' EQUITY
               
 Common stock ($0.01 par value, 20,000,000 shares authorized, 10,580,973 and 10,563,297
               
 shares issued at December 31, 2013 and December 31, 2012, respectively)
    105,810       105,633  
 Additional paid-in capital
    36,623,965       36,524,142  
 Accumulated deficit
    (23,816,064 )     (20,008,935 )
 Treasury stock, 150,000 shares and 0 shares, respectively, at cost
    (800,000 )     -  
     Total stockholders' equity
    12,113,711       16,620,840  
                 
 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
  $ 57,679,501     $ 56,381,926  
 
See accompanying notes to consolidated financial statements.
 
 
 
38

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Statements of Operations
 
   
Year Ended December 31,
 
             
   
2013
   
2012
 
             
REVENUE FROM OPERATIONS
           
Refined product sales
  $ 409,239,747     $ 351,665,234  
Pipeline operations
    303,122       406,812  
Oil and gas sales
    200       22,668  
    Total revenue from operations
    409,543,069       352,094,714  
                 
COST OF OPERATIONS
               
Cost of refined products sold
    399,101,182       342,035,755  
Refinery operating expenses
    10,673,722       8,603,155  
Pipeline operating expenses
    163,163       391,169  
Lease operating expenses
    67,923       57,122  
General and administrative expenses
    1,794,053       2,076,946  
Depletion, depreciation and amortization
    1,342,563       1,622,864  
Abandonment expense
    63,767       1,184,549  
Impairment expense
    -       9,435,745  
Bad debt expense
    -       9,508  
Accretion expense
    112,686       105,032  
Loss on disposal of property and equipment
    -       5,665  
                 
Total cost of operations
    413,319,059       365,527,510  
                 
Loss from operations
    (3,775,990 )     (13,432,796 )
                 
OTHER INCOME (EXPENSE)
               
Net tank rental and easement revenue
    1,155,064       534,047  
Interest and other income
    3,105       21,940  
Interest expense
    (1,100,053 )     (954,579 )
Total other income (expense)
    58,116       (398,592 )
                 
Loss from continuing operations before income taxes
    (3,717,874 )     (13,831,388 )
                 
Income tax expense, current
    (89,255 )     (9,678 )
Loss from continuing operations, net of tax
    (3,807,129 )     (13,841,066 )
                 
Loss from discontinued operations, net of tax
    -       (4,443,566 )
                 
Net loss
  $ (3,807,129 )   $ (18,284,632 )
                 
                 
Basic loss per common share
               
Continuing operations
  $ (0.36 )   $ (1.35 )
Discontinued operations
  $ -     $ (0.43 )
Basic loss per common share
  $ (0.36 )   $ (1.78 )
                 
Diluted loss per common share
               
Continuing operations
  $ (0.36 )   $ (1.35 )
Discontinued operations
  $ -     $ (0.43 )
Diluted loss per common share
  $ (0.36 )   $ (1.78 )
                 
Weighted average number of common shares outstanding:
               
Basic
    10,445,883       10,284,152  
Diluted
    10,445,883       10,284,152  
 
See accompanying notes to consolidated financial statements.
 
 
39

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Statements of Stockholders' Equity
 
 
 
   
Common Stock
                         
               
Additional
                     
Total
 
               
Paid-In
   
Accumulated
   
Treasury Stock
   
Stockholders’
 
   
Shares Issued
   
Par Value
   
Capital
   
Deficit
   
Shares
   
Cost
   
Equity
 
                                           
Balance at December 31, 2011
    8,426,456     $ 84,265     $ 17,302,124     $ (1,724,303 )     -     $ -     $ 15,662,086  
                                                         
Common stock issued for acquisition
    2,098,390       20,984       18,025,170       -       -       -       18,046,154  
Conversion of LE's related party accounts
                                                    -  
payable to equity on acquisition
    -       -       993,732       -       -       -       993,732  
Common stock issued for services
    30,288       303       183,197       -       -       -       183,500  
Common stock issued to exercise options
    8,163       81       19,919       -       -       -       20,000  
Net loss
    -       -       -       (18,284,632 )     -       -       (18,284,632 )
                                                         
Balance at December 31, 2012
    10,563,297       105,633       36,524,142       (20,008,935 )     -       -       16,620,840  
                                                         
Common stock issued for services
    17,676       177       99,823       -       -       -       100,000  
Treasury stock acquired
    -       -       -       -       (150,000 )     (800,000 )     (800,000 )
Net loss
    -       -       -       (3,807,129 )     -       -       (3,807,129 )
                                                         
Balance at December 31, 2013
    10,580,973     $ 105,810     $ 36,623,965     $ (23,816,064 )     (150,000 )   $ (800,000 )   $ 12,113,711  
                                                         
 
Remainder of Page Intentionally Left Blank.
 
 
 
40

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Statements of Cash Flows
 
 
   
Years Ended December 31,
 
             
   
2013
   
2012
 
OPERATING ACTIVITIES
           
   Net loss
  $ (3,807,129 )   $ (18,284,632 )
   Loss from discontinued operations
    -       4,443,566  
   Adjustments to reconcile net income (loss) to net cash
               
provided by (used in) operating activities:
               
Depletion, depreciation and amortization
    1,342,563       1,611,708  
Impairment of oil and gas properties
    -       9,435,745  
Unrealized loss (gain) on derivatives
    (143,050 )     136,100  
Amortization of debt issue costs
    33,800       33,799  
Amortization of intangible assets
    9,463       10,468  
Accretion expense
    112,686       105,032  
Abandonment costs incurred
    63,767       503,454  
Common stock issued for services
    100,000       163,499  
Bad debt expense
    -       9,508  
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
 
Restricted cash
    (237,795 )     102,411  
Accounts receivable
    1,111,649       (14,724,996 )
Prepaid expenses and other current assets
    (105,369 )     43,894  
Deposits and other assets
    16,787       (763,421 )
Inventory
    (2,385,707 )     2,288,436  
Accounts payable, accrued expenses and other liabilities
    2,846,834       12,160,088  
Accounts payable, related party
    2,065,319       3,228,128  
Net cash provided by operating activities - continuing operations
    1,023,818       502,787  
Net cash used in operating activities - discontinued operations
    -       (435,460 )
Net cash provided by operating activities
    1,023,818       67,327  
                 
INVESTING ACTIVITIES
               
Capital expenditures
    (1,477,729 )     (2,852,460 )
Proceeds from sale of assets
    201,000       -  
Cash acquired on acquisition
    -       1,674,709  
Net cash used in investing activities
    (1,276,729 )     (1,177,751 )
                 
FINANCING ACTIVITIES
               
Proceeds from issuance of debt
    5,750,611       4,788,623  
Payments on long-term debt
    (5,274,106 )     (3,276,748 )
Proceeds from notes payable
    15,032       24,548  
Payments on notes payable
    (224,805 )     (26,925 )
Proceeds from exercise of stock options
    -       20,000  
Net cash provided by financing activities
    266,732       1,529,498  
Net increase (decrease) in cash and cash equivalents
    13,821       419,074  
                 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    420,896       1,822  
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 434,717     $ 420,896  
                 
Supplemental Information:
               
Non-cash operating activities
               
Reduction in accounts receivable in exchange for treasury stock received
  $ 800,000     $ -  
Non-cash investing and financing activities:
               
Changes in estimates of existing ARO obligations
  $ 592,415     $ -  
Financing of insurance premiums
  $ -     $ 82,560  
Related party payable converted to equity
  $ -     $ 993,732  
Acquisition of Blue Dolphin at fair value, inclusive
               
of cash acquired of $1,674,594
  $ -     $ 18,046,154  
Prior period accounts payable converted to common stock
  $ -     $ 20,001  
                 
 
See accompanying notes to consolidated financial statements.
 
 
41

 
 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements
 
(1)    Organization
 
Nature of Operations

Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) is a Delaware corporation that was formed in 1986 as a holding company.  We are primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 56 acre crude oil and condensate processing facility, which is located in Nixon, Wilson County, Texas (the “Nixon Facility”).  As part of our refining business segment we also conduct petroleum storage and terminaling operations. These operations involve the storage of petroleum 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 (6) Business Segment Information” for further discussion of our business segments.

We conduct substantially all of our operations through our wholly-owned subsidiaries. Our operating subsidiaries include:

  
Lazarus Energy, LLC, a Delaware limited liability company (petroleum processing assets) (“LE”);
  
Lazarus Refining & Marketing, LLC, a Delaware limited liability company (petroleum storage and terminaling) (“LRM”);
  
Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations) (“BDPL”);
  
Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);
  
Blue Dolphin Services Co., a Texas corporation (administrative services);
  
Blue Dolphin Exploration Company, a Delaware corporation (exploration and production investments) (“BDEX”); and
  
Petroport, Inc., a Delaware corporation (inactive).

Operating Risks

We had cash and cash equivalents of $434,717 and $420,896 at December 31, 2013 and December 31, 2012, respectively, and have historically incurred recurring losses from operations. As of December 31, 2013, we were in violation of certain financial covenants in a loan agreement dated September 29, 2008 (the “Loan Agreement”) by and between LE and First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10,000,000 (the “Refinery Note”). In October 2011, the Loan Agreement was acquired by American First National Bank (AFNB). We are currently making our scheduled payments in accordance with the terms and conditions of the Loan Agreement and, as of December 31, 2013, we obtained a waiver for certain financial covenants effective through December 31, 2014.  See “Note (15) Long-Term Debt” of this report for additional disclosures related to the Refinery Note.

We currently rely on our profit share under the Joint Marketing Agreement by and between LE and GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LLC (“Genesis”), dated August 12, 2011 (the “Joint Marketing Agreement”), and Lazarus Energy Holdings, LLC (“LEH”) to fund our working capital requirements.  GEL is also the exclusive supplier of our crude oil for the Nixon Facility under the Crude Oil and Supply Throughput Services Agreement by and between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”).  During months in which we receive no profit share under the Joint Marketing Agreement, GEL and/or LEH may, but are not required to, fund our working capital requirements. There can be no assurances that GEL and/or LEH will continue to fund our working capital requirements.  In the event our working capital requirements are not funded by our profit share, GEL and/or LEH, we may experience a significant and material adverse effect on our operations.

We believe that our operational strategy, including our recent introduction and production of jet fuel and the continued refurbishment of the naphtha stabilizer and depropanizer units at the Nixon Facility, will be sufficient to support our operations over the next twelve months.  However, our efforts depend on several factors, including our future performance, levels of accounts receivable, inventories, accounts payable, capital expenditures, adequate access to credit, and financial flexibility to attract long-term capital on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive and other factors that are beyond our control.  There can be no assurance that our operational strategy will achieve the anticipated outcomes.  In the event our operational strategy is not successful, or our working capital requirements are not funded by our profit share under the Joint Marketing Agreement, GEL, or LEH, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition.
 
 
 
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Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements (Continued)

(2)
Basis of Presentation

We have prepared our audited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). The consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading.

Operations associated with the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”), which were previously reported as part of our Oil and Gas Exploration & Production business segment, have been presented as discontinued operations in the consolidated financial statements. See “Note (22) Discontinued Operations” for additional information regarding these discontinued operations. Unless stated otherwise, any reference to income statement items in these financial statements refers to results from continuing operations.

 (3)
Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the 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 current estimates are reasonable and appropriate, actual results could differ from those estimated.

Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents amounted to $434,717 and $420,896 at December 31, 2013 and December 31, 2012, respectively.

Restricted Cash
 
Restricted cash was $327,388 and $89,593 at December 31, 2013 and December 31, 2012, respectively. These amounts primarily relate to a payment reserve account required under the Refinery Note.

Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk

Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due at any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000.  We had uninsured balances of $77,388 and $170,896 at December 31, 2013 and December 31, 2012, respectively.
 
 
 
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Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements (Continued)

 
For the year ended December 31, 2013, we had 5 customers that accounted for approximately 92% of our refined petroleum product sales.  These 5 customers represented approximately $13.4 million in accounts receivable at December 31, 2013.  For the year ended December 31, 2012, we had 4 customers that accounted for approximately 84% of our refined petroleum product sales.  These 4 customers represented approximately $11.4 million in accounts receivable at December 31, 2012.

Inventory

Our inventory primarily consists of refined petroleum products.  Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.

Price-Risk Management Activities

We utilize an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand-alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential