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:
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changes in the general economic conditions;
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changes in the underlying demand for our products;
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fluctuations of crude oil inventory costs and refined petroleum products inventory prices and their effect on our refining margins;
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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;
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the early termination of our agreements with Genesis and its affiliates;
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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;
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our ability to generate sufficient funds from operations or obtain financing from other sources;
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failure to comply with certain financial covenants related to certain of our long-term indebtedness;
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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;
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availability and cost of renewable fuels for blending and Renewable Identification Numbers (“RINs”) to meet Renewable Fuel Standards ("RFS") obligations;
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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;
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potential increased indebtedness, which may reduce our financial flexibility;
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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;
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access to less than desired levels of crude oil for processing at the Nixon Facility;
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our dependence on a small number of customers for a large percentage of our revenues;
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accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our operations;
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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;
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the geographic concentration of the Nixon Facility, which creates a significant exposure risk to the regional economy;
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competition from larger companies;
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infrastructure limitations;
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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;
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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;
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retention of key personnel;
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insurance coverage that may be inadequate or expensive;
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our potential reorganization from a publicly traded “C” corporation to a publicly traded master limited partnership;
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performance of third-party operators for our oil and gas properties;
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costs associated with abandonment of our pipelines and oil and gas properties; and
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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.
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PART I
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.
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:
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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;
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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;
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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
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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 1/6
th
, 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.
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.
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.
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.
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.
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.
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.
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:
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changes in global and local economic conditions;
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domestic and foreign demand for fuel products, especially in the United States, China and India;
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worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
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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;
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availability of and access to transportation infrastructure;
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utilization rates of U.S. refineries;
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the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;
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development and marketing of alternative and competing fuels;
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commodities speculation;
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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;
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federal and state government regulations and taxes; and
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local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.
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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.
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.
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.
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.
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
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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.
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.
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:
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Property
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Business Segment(s)
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Acres
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Owned / Leased
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Location
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Nixon Facility
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Refinery Operations
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56
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Owned
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Nixon, Wilson County, Texas
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Freeport Facility
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Pipeline Transportation
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193
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Owned
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Freeport, Brazoria County, Texas
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Offshore Pipelines
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Pipeline Transportation
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--
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Owned
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U.S. Gulf of Mexico
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Oil and Gas Properties
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Exploration and Production
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Leasehold Interest
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U.S. Gulf of Mexico
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Corporate Headquarters
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Corporate and Other
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--
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Lease
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Houston, Harris County, Texas
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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.
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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.
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Offshore Pipelines
–The following provides a summary of our offshore pipelines, all of which are located in the U.S. Gulf of Mexico:
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