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


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
(Mark One)
 
 þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2014
 
or
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from             to            .

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

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

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

Securities registered pursuant to Section 12(g) of the Act:
 
(Title of class)
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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

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

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

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

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

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

The aggregate market value of shares of common stock held by non-affiliates of the registrant was $9,588,038 based on the number of shares of common stock held by non-affiliates and the last reported sale price of the registrant's common stock on December 31, 2014.
 
Number of shares of common stock, par value $0.01 per share outstanding as of March 31, 2015: 10,449,444



 
 
 
 
 
BLUE DOLPHIN ENERGY COMPANY
FORM 10-K REPORT INDEX
 
PART I    
         
  ITEM 1 BUSINESS   7
         
  ITEM 1A. RISK FACTORS   15
         
  ITEM 1B. UNRESOLVED STAFF COMMENTS   22
         
  ITEM 2. PROPERTIES   22
         
  ITEM 3. LEGAL PROCEEDINGS   23
         
  ITEM 4. MINE SAFETY DISCLOSURES   23
         
PART II    
         
  ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES   24
         
  ITEM 6. SELECTED FINANCIAL DATA   24
         
  ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS   25
         
  ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   38
         
  ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   40
         
      Report of Independent Registered Public Accounting Firm   41
         
      Consolidated Balance Sheets   42
         
      Consolidated Statements of Operations   43
         
      Consolidated Statements of Stockholders’ Equity   44
         
      Consolidated Statements of Cash Flows   45
         
      Notes to Consolidated Financial Statements   46
         
  ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   73
         
  ITEM 9A. CONTROLS AND PROCEDURES   73
         
  ITEM 9B. OTHER INFORMATION   74
         
PART III    
         
  ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE   75
         
  ITEM 11. EXECUTIVE COMPENSATION   79
         
  ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTER   81
         
  ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE   82
         
  ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES   82
         
PART IV    
         
  ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES   83
         
SIGNATURES   87
 
 
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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:

Risks Related to Our Business and Industry
 
our dependence on Lazarus Energy Holdings, LLC (“LEH”) for financing and management of our property and the property of our subsidiaries;
capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate;
our ability to use net operating loss (“NOL”) carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation;
dangers inherent in oil and gas operations that could cause disruptions and expose us to potentially significant losses, costs or liabilities and reduce our liquidity;
geographic concentration of our assets, which creates a significant exposure to the risks of the regional economy;
competition from companies having greater financial and other resources;
laws and regulations regarding personnel and process safety, as well as environmental, health and safety, for which failure to comply may result in substantial fines, criminal sanctions, permit revocations, injunctions, facility shutdowns and/or significant capital expenditures;
insurance coverage that may be inadequate or expensive;
related party transactions with LEH and its affiliates, which may cause conflicts of interest; and
loss of executive officers or key employees, as well as a shortage of skilled labor or disruptions in our labor force, which may make it difficult to maintain productivity.

Risks Related to Our Refining Operations

volatility of crude oil, other feedstocks, refined petroleum products, and fuel and utility services;
volatility of refining margins;
potential downtime at the Nixon Facility, which could result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations;
loss of market share by a key customer or consolidation among our customer base;
failure to grow or maintain the market share for our refined petroleum products;
our reliance on third-parties for the transportation of crude oil and condensate into and refined petroleum products out of the Nixon Facility;
our dependence on Genesis Energy, LLC (“Genesis”) and its affiliates for financing, crude oil and condensate sourcing, inventory risk management, hedging, and refined petroleum product marketing;
interruptions in the supply of crude oil and condensate sourced in the Eagle Ford Shale;
changes in the supply/demand balance in the Eagle Ford Shale could result in lower refining margins;
hedging of our refined petroleum products and crude oil and condensate inventory, which may limit our gains and expose us to other risks;
availability and cost of Renewable Identification Numbers and Renewable Fuel Standard mandates; and
regulation of greenhouse gas emissions, which could increase our operational costs and reduce demand for our products.
 
Risks Related to Our Pipelines and Oil and Gas Properties

asset retirement obligations for our pipelines and facilities assets and oil and gas properties.

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

The following are abbreviations and definitions of certain terms used in this document, which are 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 as 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 United States 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; based on operating days.

Capacity utilization rate.  A percentage measure that indicates the amount of available capacity that is being used at a facility.

Complexity.  A numerical score that denotes, for a given refinery, the extent, capability, and capital intensity of the refining processes downstream of the crude oil distillation unit.  The higher a refinery’s complexity, the greater the refinery’s capital investment and number of operating units used to separate feedstock into fractions, improve their quality, and increase the production of higher-valued products. Refinery complexities range from the relatively simple crude oil distillation unit (“topping unit”), which has a complexity of 1.0, to the more complex deep conversion (“coking”) refineries, which have a complexity of 12.0.

Condensate. Liquid hydrocarbons that are produced in conjunction with natural gas.  Condensate is chemically more complex than liquefied petroleum gas.  Although condensate is sometimes similar to crude oil, 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 quality is measured in terms of density (light to heavy) and sulfur content (sweet to sour). Crude oil must be broken down into its various components by distillation before these chemicals and compounds can be used as fuels or converted to more valuable products.

Crude oil distillation unit. The refinery processing unit where initial crude oil distillation takes place. See also 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 unit. 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., natural gasoline, kerosene, and light and heavy naphtha), (ii) light oils or middle distillates (e.g., kerosene, light and heavy diesel), (iii) medium oils, and (iv) heavy fuel oils.
 
 
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Distillation. The first step in the refining process whereby crude oil and condensate is heated at atmospheric pressure in the base of a distillation tower. As the temperature increases, the various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower according to their densities, from lightest to heaviest. They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities. Lighter products produced in this process can be further refined in a catalytic cracking unit or reforming unit. Heavier products, which cannot be vaporized and separated in this process, can be further distilled in a vacuum distillation unit or coker.

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

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

Feedstocks. Crude oil and other hydrocarbons, such as condensate and/or intermediate products, that are used as basic input materials in a refining process.  Feedstocks are transformed into one or more finished products.

Fractionation. The separation of crude oil and condensate 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 petroleum product that might require further processing before it is saleable to the ultimate consumer.  This further processing might be done by the producer or by another processor.  Thus, an intermediate petroleum product might be a final product for one company and an input for another company that will process it further.

Jet fuel. A high-quality kerosene product primarily used in aviation.  Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.  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. A liquid petroleum that has a low density and flows freely at room temperature.  It has a low viscosity, low specific gravity, and a high API gravity due to the presence of a high proportion of light hydrocarbon fractions.

Liquefied petroleum gas.  Manufactured during the refining of crude oil and condensate; burns relatively cleanly with no soot and very few sulfur emissions. Commonly abbreviated as LPG.

Low sulfur diesel.  Not to be confused with ultra low sulfur diesel, low sulfur diesel contains a maximum 500 ppm sulfur.

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 can make 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.  Used in locomotive, marine and non-road diesel engines and equipment, such as farm or construction equipment.  Commonly referred to as “off-road” diesel and abbreviated as NRLM.  In the United States, the EPA fuel standard for “off-road” vehicles was progressively lowered from low sulfur diesel (500 ppm sulfur) to ultra low sulfur diesel (15 ppm sulfur).
 
 
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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.

Product slate.  The type of refined petroleum products produced by the refining process.

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 oil and condensate that have been processed through various refining methods. The resulting products include gasoline, home heating oil, jet fuel, diesel, lubricants and the raw materials for fertilizer, chemicals, and pharmaceuticals. Following the refining process, the products are transported to terminals or local distribution centers for sale to various end-users and consumers.

Refinery. Within the oil and gas industry, a refinery is an industrial processing plant where crude oil and condensate is separated and transformed into marketable refined petroleum products.

Separation. The separation of the different hydrocarbons present in crude oil and condensate 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%.

Stabilizer unit. A distillation column intended to remove the lighter boiling compounds, such as butane or propane from a product.

Sweet crude. Crude oil containing sulfur content of less than 0.5%.

Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal, or natural gas. Also produced as a 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. A type of petroleum refinery that engages in only the first step of the refining process -- crude distillation.  A topping unit uses atmospheric distillation to separate crude oil and condensate into constituent petroleum products. A topping unit has a refinery complexity range of 1.0 to 2.0.

Throughput.  The volume processed through a unit or a refinery or transported through a pipeline.

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

Ultra low sulfur diesel. A cleaner-burning diesel fuel containing a maximum 15 ppm sulfur. Primarily used for highway vehicles. Commonly referred to as “on-road” diesel and abbreviated as ULSD.

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. 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.  Commonly abbreviated as WTI.

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.

Yield.  The percentage of refined petroleum products that is produced from crude oil and other feedstocks.
 
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PART I
 
ITEM 1.
 BUSINESS

Overview

Blue Dolphin Energy Company (http://www.blue-dolphin-energy.com, referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, 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, which are considered non-core to our business.

Structure and Management

We were formed as a Delaware corporation in 1986.  In connection with our reverse acquisition of Lazarus Energy, LLC (“LE”) in 2012, whereby we acquired the Nixon Facility, we:

(i)  
issued 8,426,456 shares of our common stock, par value $0.01 per share (the “Common Stock”) to Lazarus Energy Holdings, LLC (“LEH”) as consideration.  As a result, LEH, our controlling shareholder, owns approximately 81% of our Common Stock.  Jonathan P. Carroll, Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH; and
(ii)  
entered into a Management Agreement dated and effective February 12, 2012 with LEH.  Pursuant to the Management Agreement, LEH manages our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business.  On May 12, 2014, the Management Agreement was amended to: (a) extend the term to August 12, 2015, and (b) change the name of the agreement from “Management Agreement” to “Operating Agreement” (the “Operating Agreement”). 

Our operations are conducted directly and indirectly through our primary operating subsidiaries, as follows:

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

Refinery Operations
 
The Nixon Facility occupies approximately 56 acres in Nixon, Wilson County, Texas and consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, approximately 120,000 bbls of crude oil and condensate storage capacity, approximately 178,000 bbls of refined petroleum product storage capacity, and related loading and unloading facilities and utilities.

The Nixon Facility was built in 1980 and operated until 1983.  The Nixon Facility was reopened in 1986 under a new owner and operated intermittently until 1992, when it was shut down again. The Nixon Facility was acquired by LE in 2006, refurbished, and placed back into service in February 2012.

The Nixon Facility is located very close to crude oil and condensate production in the Eagle Ford Shale.  Management closely monitors and adjusts the yields of the Nixon Facility’s most profitable refined petroleum products, utilizes an inventory risk management policy to reduce commodity price risk, and tightly manages refinery operating expenses in an effort to maximize refining margins. Under our inventory risk management policy, Genesis may, but is not required to, use derivative instruments when certain of our refined petroleum product inventories exceed certain thresholds.
 
 
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Process Summary

With a capacity of 15,000 bpd, the Nixon Facility is considered a “topping unit” because it is primarily comprised of a crude distillation unit, the first stage of the crude oil refining process.  “Topping units” are typically smaller than full-scale refineries and are usually located near the primary market for their key product. The Nixon Facility’s level of complexity allows us to refine crude oil and condensate into finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, LPG, atmospheric gas oil, and oil-based mud blendstock.  Finished products are sold in nearby markets and intermediate products are sold to wholesalers and nearby refineries for further blending and processing.  The Nixon Facility uses light crude oil and condensate sourced in the Eagle Ford Shale as feedstock.

During 2014, we continued refurbishment of key components of the Nixon Facility, including the naphtha stabilizer and depropanizer units.  Once operational, the naphtha stabilizer and depropanizer units will improve the overall quality of the naphtha that we produce, allow higher recovery of lighter products that can be sold as LPG mix, and increase the amount of throughput that can be processed by the Nixon Facility.  The below diagram represents a high level overview of the current crude oil and condensate refining process at the Nixon Facility.

 
 Example represents a simplified plant configuration.  The specific configuration will vary based on various market and operational factors.
 
 
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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. Crude oil refining is primarily a margins-based business where both crude oil and refined petroleum products are commodities with prices that can fluctuate independently for short periods due to supply, demand, transportation and other factors.  In order to increase profitability, or improve margins, it is important for a crude oil refinery to maximize the yields of high value finished petroleum products and to minimize the costs of feedstocks and operating expenses.  There are also a number of operational efficiencies that can be deployed to improve margins.  These include selecting the appropriate crude oil or condensate to fulfill anticipated product demand, increasing the amount and value of refined petroleum products processed from the crude oil or condensate, reducing down-time for maintenance, repair and investment, developing valuable by-products or production inputs out of materials that are typically discarded, and adjusting utilization rates (operating at a high utilization rate when margins are high and, conversely, reducing production and buying of feedstocks when margins are low).

Crude oil and condensate supply and demand dynamics vary by region, creating differentiated margin opportunities based on the refinery’s location.  The Nixon Facility is located in the Gulf Coast region of the United States, which is represented by the Energy Information Administration (the “EIA”) as Petroleum Administration for Defense District 3 (“PADD 3”).

A refinery’s product slate depends on market demand, the type of crude oil and/or condensate being refined, and the refinery’s complexity.  Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined petroleum products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined petroleum products.  The effect of changes in crude oil prices on a refinery’s results of operations depends, in part, on how quickly and how fully refined petroleum products prices adjust to reflect these changes.

Raw Material Supply

The primary input for the Nixon Facility is crude oil and condensate, which represented approximately 100% of our total refinery throughput volumes for the years ended December 31, 2014 and 2013.  As a result of the declining price of crude oil and condensate during the last quarter of 2014, our average crude oil and condensate costs were lower.  We processed 11,599 bpd and 11,209 bpd of crude oil and condensate for the years ended December 31, 2014 and 2013, respectively.

Crude Oil and Condensate Supply

We purchase the light crude oil and condensate for the Nixon Facility pursuant to an exclusive Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) with GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis.  We have the ability to purchase crude oil and condensate from other suppliers 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.   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.  See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for more information related to the Crude Supply Agreement.

Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years.  The initial term ended on August 12, 2014.  However, 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.

Crude oil and condensate is currently received at the Nixon Facility by truck and stored in tanks.  The Nixon Facility property is crossed by a crude oil and condensate pipeline owned by Koch Pipeline Company.  The pipeline represents a potential future opportunity to receive crude oil and condensate at the Nixon Facility, thereby reducing trucking costs.

Electrical Power Supply

A regional electric cooperative supplies electrical power to the Nixon Facility.
 
 
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Fuel Supply

Light distillates that are produced at the Nixon Facility are used as fuel within the refinery.  In addition, small amounts of propane are occasionally acquired for use in starting-up the Nixon Facility.

Turnaround and Refinery Reliability

We are committed to the safe and efficient operation of the Nixon Facility.  Turnarounds are used to repair, restore, refurbish or replace refinery equipment such as vessels, tanks, reactors, piping, rotating equipment, instrumentation, electrical equipment, heat exchangers and fired heaters.  Typically a refinery undergoes a major facility turnaround every three to five years.  Since the Nixon Facility is still in the recommissioning phase, one or more of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds.

Petroleum Refining Market and Competition

The principal competitive factors affecting refineries are crude oil and other feedstock costs, capacity utilization rates, refinery operating expenses, refined petroleum products mix, and product distribution/transportation costs.  Many of our principal competitors are larger, integrated independent or multi-national oil companies (such as Valero, Chevron, ExxonMobil, Shell and ConocoPhillips). These competitors are often 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 because of their larger capitalization, diversified operations, multiple locations, and larger refinery complexities,.

We compete primarily on the basis of cost.  Due to the low complexity of our simple “topping unit” refinery, we can be relatively nimble in adjusting our refined petroleum products slate as a result of changing commodity prices, market demand, and refinery operating costs.   The Nixon Facility, which is located in the Eagle Ford Shale, supplies intermediate and finished petroleum products primarily to customers in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area).

Despite the United States’ current surplus refining capacity, 50% of which is located in PADD 3 (Gulf Coast), the rise in production of light sweet crude oil from unconventional sources such as the Bakken Shale and the Eagle Ford Shale has revitalized some refinery operations that formerly depended on imported light sweet crude oil.  As a result, small refineries like the Nixon Facility are more competitive with large refineries that process more widely available, lower quality heavy-sour crude oil.  In order to remain competitive, large refineries need significant pricing discounts on light sweet crude oil in order to displace lower quality heavy-sour crude oil.

Refining Operations Customers

Customers for our intermediate and finished 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 intermediate and finished petroleum products. For the year ended December 31, 2014, our five largest customers accounted for approximately 89% of our refined petroleum products sales.  For the year ended December 31, 2013, our five largest customers accounted for approximately 92% of our refined petroleum products sales.

Insurance and Risk Management

Our operations are subject to significant hazards and risks inherent in crude oil and condensate refining operations and in the transportation and storage of crude oil and condensate, as well as intermediate and finished petroleum products.  We have property damage and business interruption coverage at the Nixon Facility, as well as business interruption coverage for 24 months from the date of the loss, subject to a deductible with a 45 day waiting period.  Our property damage insurance has deductibles ranging from $5,000 to $500,000.  In addition, we have a full suite of insurance policies covering workers compensation, general liability, directors’ and officers’ liability, environmental liability, and other business risks.  These are supported by safety and other risk management programs.  See also, “Item 1A. Risk Factors – Risks Related to Our Business” in this report.
 
 
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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, as well as leasehold interests in oil and natural gas properties, in the Gulf of Mexico. Our pipeline transportation operations represented less than 1% of total revenue for the years ended December 31, 2014 and 2013.

Ongoing Acquisition and Disposition Activities

Consistent with our growth strategy, we are continuously engaged in discussions with potential sellers of assets, including 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.

Governmental Regulation

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 of this report, which discuss our expectations regarding future events, results or outcomes based on currently available information.

Air Emissions

The federal Clean Air Act (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 Environmental Protection Agency (the “EPA”) has, in the past, targeted petroleum refineries as part of a nationwide enforcement initiative, and refineries remain high-visibility targets for enforcement under the CAA. In 1992, the EPA published a list of source categories (industry groups) that emit one or more of a list of 188 hazardous air pollutants (“HAPs”), also known as air toxics. The list of industry groups includes petroleum refineries because they are considered to be a major source of HAP emissions. The EPA developed standards that require the application of maximum achievable control technology (“MACT”) to help control HAP emissions. The Petroleum Refinery MACT standard applies to petroleum refining process units and related emission points. We are required to obtain permits, as well as to test, monitor, report, and implement control requirements. In addition, our operations are subject to a number of New Source Performance Standards (“NSPS”) regulations. For example, in September 2012, the EPA issued final revisions to the NSPS for process heaters and flares at petroleum refineries. The final NSPS regulate emissions of nitrogen oxide from process heaters and emissions of sulfur dioxide from flares. The final rule also establishes work practice and monitoring standards for flares. In addition, air permits incorporating stringent control technology requirements are required for our refining operations that result in the emission of regulated air contaminants.
 
 
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The CAA authorized 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 transportation fuels. These standards required most refineries to produce transportation fuels for highway use at 15 ppm sulfur for “on-road” diesel and 30 ppm sulfur for gasoline. “Off-road” diesel requirements were reduced to 15 ppm sulfur in June 2014. The Nixon Facility does not currently produce gasoline or transportation-related diesel fuel products.

Fuel Quality Requirements

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 (the “Energy Acts of 2005 and 2007”), the EPA issued Renewable Fuels Standards (“RFS”) that require the blending of biofuels into transportation fuel. Since the compliance mechanism for RFS - Renewable Identification Numbers (“RINs”) – would create a burden on the Nixon Facility related to its NRLM production through May 2014, we applied for an extension of the temporary exemption afforded small refineries through December 31, 2010 under the CAA Section 211(o)(9)(B).  In September 2014, the EPA granted the Nixon Facility a small refinery exemption from RFS requirements for 2013 and 2014.

On May 31, 2014, the Nixon Facility ceased production of NRLM, a transportation-related diesel fuel product.  On June 1, 2014, the Nixon Facility began producing oil-based mud blendstock, a non-transportation lubricant blend product.  The shift in product slate from NRLM to oil-based mud blendstock was the result of the EPA’s phased-in requirements for small refineries to reduce the sulfur content in transportation-related diesel fuel, such as NRLM, to a maximum of 15 ppm sulfur by June 1, 2014.  “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the fuel quality standards implemented by the EPA in June 2014, and integration of such a desulfurization unit generally requires additional permitting and significant capital upgrades.  The Nixon Facility can still produce diesel with higher sulfur content as a feedstock to other refineries and blenders in the United States and as a finished petroleum product to other countries.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act (“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.

We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), and comparable state and local laws, which impose requirements related to the handling, storage, treatment and disposal of solid and hazardous wastes.  In our refining operations, we generate petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. In addition, our operations also generate solid wastes, which are regulated under RCRA and state law.  The Nixon Facility has been used for refining activities for many years. Although prior owners and operators may have used operating and waste disposal practices that were standard in the industry at the time, petroleum hydrocarbons and various wastes may have been released on or under the Nixon Facility site. A 2008 third-party environmental study determined that petroleum hydrocarbon and volatile organic compound concentrations were below Tier 1 protective concentration levels (“PCLs”).  However, RCRA-8 metals were found to be above Tier 1 PCLs.  An additional third-party study determined that metal concentrations from the soil would not leach beyond groundwater concentrations exceeding their respective PCLs.  As a result, groundwater resources would not be threatened and no further reporting was required.  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.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. 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 requirements mandate the use of structures, such as berms and other secondary containment, to prevent hydrocarbons or other pollutants from reaching a jurisdictional body of 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.
 
 
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Stormwater from the Nixon Facility is tested and discharged pursuant to applicable stormwater permit(s).  Process wastewater from the Nixon Facility is tested and discharged to a nearby municipal treatment facility pursuant to applicable process wastewater permit(s). Wastewater from our offshore facilities, including our oil and natural gas pipelines and anchor platform, are tested and discharged pursuant to applicable produced water permit(s).
 
Pipelines and Onshore Facilities

The Oil Pollution Act of 1990 (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 United States 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.

Our pipeline operations and exploration and production activities within federal waters are also subject to the requirements of the Outer Continental Shelf Lands Act (the “OCSLA”). OCSLA 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.

Financial Assurance

We are required to satisfy BOEM supplemental pipeline bonding requirements with regard to certain pipelines that we operate in federal waters of the Gulf of Mexico.  These supplemental pipeline bonding requirements are intended to secure our performance of plugging and abandonment obligations with respect to these pipelines. Once plugging and abandonment work has been completed, the collateral backing the supplemental pipeline bonds will be released to us.

In August 2006, BDPL secured a $700,000 supplemental pipeline bond for Right-of-Way Number OCS-G 01381.  On February 5, 2014, WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”) whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013.  Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for additional supplemental pipeline bonds for the benefit of BDPL in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets.  The $850,000 in cash was used to: (i) increase the supplemental pipeline bond for Right-of-Way Number OCS-G 01381 by $205,000, increasing the total cash-backed collateral for this right-of-way to $905,000, and (ii) secure a $645,000 cash-backed supplemental pipeline bond for Right-of-Way Number OCS-G 08606.

In December 2014, BDPL completed plugging and abandonment work for Right-of-Way Number OCS-G 08606.  As a result, BDPL anticipates release by BOEM of the collateral backing this supplemental pipeline bond in the first half of 2015.  There can be no assurance that BOEM will not require additional supplemental pipeline bonds related to other BDPL pipeline right-of-ways.
 
 
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Health, Safety and Maintenance

We are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act ("OSHA") and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.

We operate a comprehensive safety, health and security program, with participation by personnel at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely monitor our programs and consider improvements in our management systems.

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, the Nixon Facility is subject to inspections that may last from two to six months, including one to three months onsite. Inspectors primarily focus on process safety management implementation and recordkeeping. The Nixon Facility was the subject of an OSHA inspection in 2013. As a result of the inspection, the Nixon Facility entered into an OSHA settlement agreement in 2014, pursuant to which we agreed to comply with abatement certification provisions primarily related to documentation and posting requirements and paid a penalty totaling $38,500.

Climate Change

In 2007 the United States Supreme Court held in Massachusetts v. EPA that emission of greenhouse gases (“GHGs”) may be regulated as an air pollutant under the CAA. In December 2009, the EPA published its findings that GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions present a potential danger to public health and the environment. As a result of these findings, the EPA has adopted and implemented regulations that have or will restrict emissions of GHGs under existing provisions of the CAA.

Transportation/Mobile Sources – The EPA and the National Highway Traffic Safety Administration (“NHTSA”) have taken steps to enable the production of clean vehicles through reduced GHG emissions and improved fuel use from on-road vehicles and engines.   On August 28, 2012, the EPA and NHTSA finalized standards to extend the light-duty vehicle GHG National Program for model years 2017-2025.  The agencies also adopted first-ever GHG regulations for heavy-duty engines and vehicles.  The EPA is also responsible for developing and implementing regulations to ensure that transportation fuel sold in the United States contains a minimum volume of renewable fuel.  [See “Part I. Item 1. Business – Governmental Regulation – Fuel Quality Requirements” of this report for additional information related to RFS.]  On May 31, 2014, the Nixon Facility ceased production of NRLM, a transportation-related diesel fuel product.

Stationary Sources – On May 13, 2010, the EPA set GHG emissions thresholds to define when permits under the New Source Review Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs are required for new and existing industrial facilities. This final rule "tailors" permitting programs to apply to certain stationary sources of GHG emissions and establishes a schedule that initially focuses the CAA’s permitting programs on the largest sources with the most CAA permitting experience. The rule then expands to cover the largest sources of GHG that may not have been previously covered by the CAA for other pollutants. Also in its final rule, the EPA committed to undertake another rulemaking, to begin in 2011 and conclude no later than July 1, 2012 related to possibly phasing in GHG permitting and whether certain smaller sources can be permanently excluded from permitting.   To date, the EPA has issued no further rulings on this matter.  The adoption of any regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the Nixon Facility could require us to incur significant costs and expenses or changes in operations, which could adversely affect our operations and financial condition.
 
Environmental

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (22) Commitments and Contingencies – Health, Safety and Environmental Matters” of this report for a description of our environmental activities.

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 United States in name and logo form. “Petroport” is a registered trademark in the United States in name form. In addition, “blue-dolphin-energy.com” is a registered domain name.
 
 
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Personnel

We rely on the services of LEH pursuant to an Operating Agreement to manage our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business.  LEH provides us with the following services under the Operating Agreement, among others:

Personnel serving in capacities equivalent to the capacities of corporate executive officers, including Chief Executive Officer and interim Chief Financial Officer, as well as general manager and environmental, health and safety; and
Personnel providing administrative and professional services, including accounting, human resources, insurance, and regulatory compliance.

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (9), Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement.

Available Information

The Securities and Exchange Commission (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.
 
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 may 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 may also materially adversely affect our business, financial condition, operating results and/or cash flows.

Risks Related to Our Business and Industry

Our operations are highly dependent on our relationships 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 and condensate, transportation of crude oil and condensate, and other services. 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 related to inventory risk management, which is intended to reduce the commodity price risk of our refined petroleum product inventories and generate a more consistent gross profit margin for each barrel of refined petroleum products.

LEH manages our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business pursuant to the Operating Agreement.  The Operating 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, 2015, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating 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.
 
 
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We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
 
If we are unable to generate sufficient cash flows 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 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 related to repayment of debt obligations and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs primarily relate to repayment of long-term debt obligations.  In addition, we continue to utilize capital to 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.
 
Our ability to use NOL carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.
 
Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).
 
As of December 31, 2014, we reported a net deferred tax asset of approximately $5.7 million. Blue Dolphin experienced ownership changes in 2005 in connection with a series of private placements, and in 2012 as a result of the reverse acquisition of LE.  The 2012 ownership change limits our ability to utilize NOLs following the 2005 ownership change that were not previously subject to limitation. Limitations imposed on our ability to use NOLs to offset future taxable income could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect, and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes. NOLs generated after the 2012 ownership change are not subject to limitation.
 
Genesis and LEH may, but are not required to, fund our working capital requirements in the event our internally generated cash flows and other sources of liquidity are inadequate.

Historically, we have relied on Genesis and/or LEH to fund our working capital requirements when cash reserves and revenue from operations, including sales of refined petroleum products and rental of storage tanks, were insufficient to fund our working capital requirements. As of December 31, 2014 and 2013, working capital requirements financed by LEH were $1,174,168 and $3,659,340, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets.  We expect that these resources will be sufficient to satisfy our anticipated working capital requirements over the next 12 to 18 months. In the event our working capital requirements are not funded by Genesis and/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.  Our long-term needs for cash include ongoing capital expenditures for equipment to improve the Nixon Facility and reduce operational, safety and environmental risks. Our liquidity will affect our ability to satisfy any of these needs.

The dangers inherent in oil and gas operations could expose us to potentially significant losses, costs or liabilities and reduce our liquidity.

Oil and gas operations are inherently subject to significant hazards and risks. These hazards and risks include, but are not limited to, fires, explosions, ruptures, blowouts, spills, third-party interference and equipment failure, any of which could result in interruption or termination of operations, pollution, personal injury and death, or damage to our assets and the property of others. These risks could harm our reputation and business, result in claims against us, and have a material adverse effect on our results of operations and financial condition.

The geographic concentration of our assets creates a significant exposure to the risks of the regional economy and other regional adverse conditions.

Our primary operating asset, the Nixon Facility, is located in Nixon, Wilson County, Texas in Texas’ Eagle Ford Shale and we market our refined petroleum products in a single, relatively limited geographic area.  In addition, our onshore facilities assets are located in Freeport, Brazoria County, Texas, and all of our pipelines and oil and gas properties are located within the Gulf of Mexico.  As a result, our operations are more susceptible to regional economic conditions than our more geographically diversified competitors.  Any changes in market conditions, unforeseen circumstances or other events affecting the area in which our assets are located could have a material adverse effect on our business, financial condition, and results of operations. These factors include, among other things, changes in the economy, weather conditions, demographics, and population.
 
 
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Competition from companies having greater financial and other resources than we do could materially and adversely affect our business and results of operations.

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in PADD 3 (Gulf Coast), 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 higher margins per barrel of production. 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 supplier. Because of their integrated operations and larger capitalization, larger, more complex refineries may be more flexible in responding to volatile industry or market conditions, such as crude oil and other feedstocks supply shortages or commodity price fluctuations.  If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.

We are subject to strict laws and regulations regarding personnel 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 personnel 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 under, or costs and capital expenditures to comply with, environmental, health and safety regulations, which are complex and change frequently.
 
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, incur increased operating costs, or change operations to achieve compliance with applicable standards and regulations.  For example:

We review, on an ongoing basis, 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 costs in the future, which could result in additional obligations and expenses, including fines and penalties;
On September 12, 2012, the EPA published final amendments to 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; and
New environmental regulations became effective in June 2014 that require most refineries to produce transportation-related fuels for highway and non-highway use at 15 ppm sulfur. In order to meet the lower sulfur content requirement for NRLM in the United States, the Nixon Facility will 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. The Nixon Facility can continue to sell diesel with high 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 petroleum product, or (iii) sell higher sulfur diesel content at prices that we deem reasonable or at all.
 
 
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Capital expenditures or costs for compliance with existing environmental, health and safety regulations could have a material adverse effect on our results of operations, financial condition and profitability.  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.

Our insurance policies may be inadequate or expensive.
 
Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience insurable events, our annual premiums could increase further or insurance may not be available at all or if it is available, on limited coverage items. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our business, financial condition, and results of operations and, as a result, our ability to make distributions.

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 Operating 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 Operating Agreement.

LEH owns approximately 81% of our 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.

Our business may suffer if any of the executive officers or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain productivity.
 
Our future success depends to a large extent on the services of the executive officers and other key employees and on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations.  Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business could be materially adversely affected.
 
 
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Risks Primarily Related to Our Refining Operations
 
The price volatility of crude oil, other feedstocks, refined petroleum 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 condensate that are processed and blended into refined petroleum products) at which we are able to sell as refined petroleum products. Crude oil refining is primarily a margin-based business.  In order to improve margins, it is important for a crude oil refinery to maximize the yields of high value finished petroleum produces and to minimize the costs of feedstocks and operating expenses. When the margin between refined petroleum product prices and crude oil and other feedstock costs decreases, our margins are negatively affected. Crude oil refining margins have historically 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 petroleum 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 petroleum products, there may be a time lag in the realization of the similar increase or decrease in prices for refined petroleum products. The effect of changes in crude oil and condensate prices on our refining margins therefore depends, in part, on how quickly and how fully refined petroleum product prices adjust to reflect these changes.

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

changes in global and local economic conditions;

domestic and foreign demand for fuel products, especially in the United States, China and India;

worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;

the level of foreign and domestic production of crude oil, other feedstocks, and refined petroleum products and the volume of crude oil, feedstocks, and refined petroleum products imported into the United States;

availability of and access to transportation infrastructure;

capacity utilization rates of refineries in the United States;

the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;

development and marketing of alternative and competing fuels;

commodities speculation;

natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;

federal and state government regulations and taxes; and

local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

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

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our refined petroleum product sales prices and our crude oil and condensate costs.  Our crude oil and condensate acquisition costs and the prices at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control.
 
 
19

 

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 “refinery operations” business segment margins will fall unless we are able to pass along these price increases to our wholesale customers. Increases in the 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.

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, and we are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility. 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. Occasionally, the Nixon Facility experiences a temporary shutdown due to power outages as a result of high winds and thunderstorms.  In the case of such a shutdown, the refinery must initiate a standard start-up process, and such process can last several days although we are typically able to resume normal operations the next day.  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.

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, 2014, 89% of our refined petroleum products sales came from 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 the market share 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 and condensate 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 condensate and sell refined petroleum products to wholesale markets could be materially and adversely affected.

We rely on trucks for the receipt of crude oil and condensate 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, condensate, and/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.

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 have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL.  We are dependent on GEL for the provision of our crude oil and condensate.  The loss of GEL as our crude oil and condensate supplier, to the extent we were unable to find another crude oil and condensate supplier, would adversely affect our financial results.
 
 
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To the extent that GEL reduces the volume of crude oil and other feedstocks that they supply to us as a result of declining production, 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 and condensate 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 and condensate that we refine.

Our supplier sources a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale and may experience interruptions of supply from that region.
 
Our supplier sources a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale. As a result, we may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by transportation capacity constraints, curtailment of production, unavailability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in that area.
 
Our refining operations and customers are primarily located within the Eagle Ford Shale and changes in the supply/demand balance in this region could result in lower refining margins.
 
Our primary operating asset, the Nixon Facility, is located in Texas’ Eagle Ford Shale and we market our refined petroleum products in a single, relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than our more geographically diversified competitors.  Should the supply/demand balance shift in our region as a result of changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the PADD 3 (Gulf Coast) region to exceed demand, we would have to deliver refined petroleum products to customers outside of our current operating region and thus incur considerably higher transportation costs, resulting in lower refining margins.
 
Hedging of our refined petroleum products and crude oil and condensate may limit our gains and expose us to other risks.
 
We are exposed to commodity price risk related to our refined petroleum products and crude oil and condensate inventories. The spread between the cost of crude oil and condensate and refined petroleum product sales prices is the primary factor affecting our operations, liquidity and financial condition. Our feedstock 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, and 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.
 
Under our inventory risk management policy, Genesis may, but is not required to, use derivative instruments as certain of our refined petroleum product inventories exceed certain thresholds in an effort to reduce our 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.
 
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 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.  In September 2014, the EPA granted the Nixon Facility a small refinery exemption from RFS requirements for 2013 and 2014.  Recently the price of RINs has been extremely volatile. 
 
 
21

 

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 and other hydrocarbons 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.

Risks Related to Our Pipelines and Oil and Gas Properties

Asset retirement obligations for our pipelines and facilities assets and oil and gas properties are estimates, and actual costs could vary significantly.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive pipelines and related assets and non-producing oil and gas properties in which we have a working interest. Such asset retirement obligations may include complete structural removal and/or restoration of the land or seabed. Although management has used its best efforts to determine future asset retirement obligations, assumptions and estimates can be influenced by many factors beyond management’s control, including, but not limited to, changes in regulatory requirements, which may be more restrictive in the future, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes, which may cause structural or other damage to pipeline and related assets and oil and gas properties. Accordingly, our estimate of future asset retirement obligations could differ materially from actual costs that may be incurred.  As of December 31, 2014, our estimated future asset retirement obligations were $3.3 million.  See “Part II, Item 8. Financial Statements and Supplementary Data – Note (12) Asset Retirement Obligations” of this report for additional information regarding asset retirement obligations.
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS

None.
 
ITEM 2.  PROPERTIES

Owned and Leased Assets

We own, lease, and have leasehold interests in the properties listed below:
 
Property   Business Segment(s)   Acres   Owned / Leased   Location
Nixon Facility   Refinery Operations   56   Owned   Nixon, Wilson County, Texas
Freeport Facility   Pipeline Transportation   193   Owned   Freeport, Brazoria County, Texas
Pipelines and Oil and Gas Properties   Pipeline Transportation   --   Owned/Leasehold Interests   Gulf of Mexico
Corporate Headquarters   Corporate and Other   --   Lease   Houston, Harris County, Texas
 
 
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LEH manages and operates all of our properties and is reimbursed for their management and operation under the Operating Agreement.  We believe that our properties are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business.

Nixon Facility – Located in Nixon, Wilson County, Texas, the 15,000 bpd Nixon Facility is a 56 acre crude oil and condensate processing facility that consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, approximately 120,000 bbls of crude oil and condensate storage capacity, approximately 178,000 bbls of refined petroleum products storage capacity and related loading and unloading facilities and utilities. The Nixon Facility is currently undergoing upgrades and refurbishment of certain components, including the naphtha stabilizer and depropanizer units. The Nixon Facility is pledged as collateral under a Security Agreement as discussed in Part II, Item 8 “Financial Statements and Supplementary Data – Note (13) Long-Term Debt” of this report.
 
Freeport Facility – Located in Freeport, Brazoria County, Texas, the Freeport Facility encompasses approximately 193 acres of land and includes pipeline easements and right-of-ways, crude oil and natural gas separation and dehydration facilities, a vapor recovery unit and two onshore pipelines.  The two onshore pipelines consist of approximately 4 miles of the 20-inch Blue Dolphin Pipeline and a 16-inch natural gas pipeline that connects the Freeport Facility to the Dow Chemical Plan Complex in Freeport, Texas.

Pipelines and Oil and Gas Properties –The following provides a summary of our offshore pipelines, all of which are located in the Gulf of Mexico:
 
Pipeline
  Location   Ownership   Miles  
Natural Gas
Capacity
(MMcf/d)
                 
Blue Dolphin Pipeline(1)   Gulf of Mexico   100%   38   180
GA 350 Pipeline   Gulf of Mexico   100%   13   65
Omega Pipeline(2)   Gulf of Mexico   100%   18   110

(1)  
Currently inactive.
(2)  
Currently abandoned in place.
 
o  
Blue Dolphin Pipeline System (“Blue Dolphin Pipeline”) – The Blue Dolphin Pipeline consists of 16-inch and 20-inch pipeline segments, including a trunk line and lateral lines, that span approximately 38 miles and run from an offshore anchor platform in Galveston Area Block 288 to our Freeport Facility.  The Blue Dolphin Pipeline has an aggregate capacity of approximately 180 MMcf of natural gas and 7,000 bbls of crude oil and condensate per day.  The Blue Dolphin Pipeline is currently inactive;

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

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

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

Corporate Headquarters – Our company headquarters is located downtown in Houston, Harris County, Texas.  We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH.  Our office lease is discussed more fully in Part II, Item 8 “Financial Statements and Supplementary Data – Note (17) Leases” of this report.
 
ITEM 3.  LEGAL PROCEEDINGS

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. Vendors have placed mechanic’s liens on the Nixon Facility as protection during construction activities. Management does not believe that such liens have a material adverse effect on our results of operations.
 
ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.
 
 
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PART II
 
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock, par value $0.01 per share (the “Common Stock”) currently trades on the OTCQX U.S. Premier tier of the OTC Markets under the ticker symbol “BDCO."  The following table sets forth, for the periods indicated, the high and low prices for our Common Stock as reported by the NASDAQ and the OTC Markets.  The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.
 
Quarter Ended
 
High
   
Low
 
             
2014
           
December 31
  $ 6.20     $ 3.51  
September 30
  $ 9.99     $ 5.99  
June 30
  $ 10.75     $ 3.50  
March 31
  $ 6.05     $ 4.75  
                 
2013
               
December 31
  $ 6.90     $ 4.15  
September 30
  $ 7.00     $ 5.01  
June 30
  $ 6.49     $ 5.12  
March 31
  $ 9.97     $ 5.00  

Holders

As of March 31, 2015, we had 273 record holders of our Common Stock. We have approximately 3,000 beneficial holders of our Common Stock.

Dividends

We have not declared or paid any dividends on our Common Stock since our incorporation.  We currently intend to retain earnings for our capital needs and expansion of our business and do not anticipate paying cash dividends on the Common Stock in the foreseeable future. We expect that any loan agreements we enter into in the future will likely contain restrictions on the payment of dividends on our Common Stock. Future policy with respect to dividends will be determined by the Board based upon our earnings and financial condition, capital requirements and other considerations.
 
ITEM 6.
SELECTED FINANCIAL DATA

Not applicable.
 
 
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ITEM 7. 
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

Our refinery operations consist primarily of the 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Wilson County, Texas (the “Nixon Facility”). The Nixon Facility’s complexity allows us to refine crude oil and condensate into finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, LPG and atmospheric gas oil.  The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, approximately 120,000 bbls of crude oil and condensate storage capacity, approximately 178,000 bbls of refined petroleum product storage capacity, and related loading and unloading facilities and utilities. The Nixon Facility is currently undergoing upgrades and refurbishment of certain components, including the naphtha stabilizer and depropanizer units. 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, which are considered non-core to our business. Certain of our pipelines are inactive, and all of the leases associated with our oil and gas properties have expired.

Refinery Operations Business Strategy

We are committed to maintaining safe, efficient and reliable refinery operations, improving margins, and focusing on safety and environmental stewardship.   Throughout 2014, we advanced our refinery operations business strategy by: (i) continuing to implement programs and procedures at the Nixon Facility to improve safety, (ii) improving product mix through the introduction of oil-based mud blendstock in June 2014 and the increased production of jet fuel, and (iii) upgrading and refurbishing certain components of the Nixon Facility, including the naphtha stabilizer unit, depropanizer unit, and two boilers. We anticipate that completion of these capital improvement projects will:

Naphtha Stabilizer and Depropanizer Units – improve the overall quality of the naphtha that we produce, allow higher recovery of lighter products that can be sold as LPG mix, and increase the amount of throughput that can be processed by the Nixon Facility; and

Boilers – reduce fuel gas usage since the new boilers will be more energy efficient and have the ability to operate using natural gas. This will, in turn, reduce emissions of combustion-related pollutants and potential operational downtime.

Major Influences on Results of Operations

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

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

In connection with our reverse acquisition of Lazarus Energy, LLC (“LE”) in 2012 whereby we acquired the Nixon Facility, we:

(i)  
issued 8,426,456 shares of our Common Stock to Lazarus Energy Holdings, LLC (“LEH”) as consideration.  As a result, LEH, our controlling shareholder, owns approximately 81% of our Common Stock.  Jonathan P. Carroll, Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH; and
(ii)  
entered into a Management Agreement dated and effective February 12, 2012 with LEH.  Pursuant to the Management Agreement, LEH manages our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business.  On May 12, 2014, the Management Agreement was amended to: (a) extend the term to August 12, 2015, and (b) change the name of the agreement from “Management Agreement” to “Operating Agreement” (the “Operating Agreement”). 

We currently rely on our profit share, GEL TEX Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LLC (“Genesis”), and LEH to fund our working capital requirements. During months in which we receive no profit share distribution, GEL and/or LEH may, but are not required to, fund our operating losses.
 
Relationship with Genesis

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

Crude Supply Agreement – Pursuant to the Crude Supply Agreement, GEL, an affiliate of Genesis, is the exclusive supplier of crude oil and condensate to the Nixon Facility. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. GEL supplies crude oil and condensate to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice.

Construction and Funding Agreement – Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam made advances in excess of their obligation for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits (as defined below) of LE in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil and condensate) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.
 
So long as the Construction and Funding Agreement remains in effect, LE is prohibited from:  (i) incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); (ii) selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; (iii) suffering any change of control or merging with or into another entity; and (iv) certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement by written notice at any time. If Milam terminates the Construction and Funding Agreement, then Milam and LE are required to execute a forbearance agreement, the form of which has previously been agreed to as Exhibit J of the Construction and Funding Agreement.


 
In accordance with the terms of the October 2013 Letter Agreement, GEL agreed to advance to LE monies not to exceed approximately $186,934 to pay for certain equipment and services at the Nixon Facility.  All amounts advanced or paid by GEL or its affiliates pursuant to the October 2013 Letter Agreement constitute Obligations, as defined in the Construction and Funding Agreement, by LE to Milam under the Construction and Funding Agreement.
 
 
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Joint Marketing Agreement – The Joint Marketing Agreement sets forth the terms of an agreement between LE and GEL pursuant to which the parties will jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement) as follows:

(a)
First, prior to the date on which Milam has recouped all amounts advanced to LE under the Construction and Funding Agreement (the “Investment Threshold Date”), the Base Construction Payment of $150,000 shall be paid to GEL (for remittance to Milam) each calendar month to satisfy amounts owed under the Construction and Funding Agreement, with a catch-up in subsequent months if there is a Deficit Amount until such Deficit Amount has been satisfied in full.

(b)
Second, prior to and as of the Investment Threshold Date, LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees. If Gross Profits are less than $900,000, then LE’s Operations Payments shall be reduced to equal to the difference between the Gross Profits for such monthly period and the proceeds discussed in (a) above; if Gross Profits are negative, then LE does not get an Operations Payment and the negative balance becomes a Deficit Amount which is added to the total due and owing under the Construction Funding Agreement and such Deficit Amount must be satisfied before any allocation of Gross Profit in the future may be made to LE.

(c)
Third, prior to the Investment Threshold Date and subject to the payment of the Base Construction Payment by LE and the Operations Payments by GEL, pursuant to (a) and (b) above, an amount shall be paid to GEL from Gross Profits equal to transportation costs, tank storage fees (if applicable), financial statement preparation fees (collectively, the “GEL Expense Items”), after which GEL shall be paid 80% of the remaining Gross Profits (any percentage of Gross Profits distributed to GEL, the “GEL Profit Share”) and LE shall be paid 20% of the remaining Gross Profits (any percentage of Gross Profits distributed to LE, the “LE Profit Share”); provided, however, that in the event that there is a forbearance payment of Gross Profits required by LE under a forbearance agreement with a bank, then 50% of the LE Profit Share shall be directly remitted by GEL to the bank on LE’s behalf until such forbearance amount is paid in full; and provided further that, if there is a Deficit Amount due under the Construction and Funding Agreement and a forbearance payment of Gross Profits that would otherwise be due and payable to the bank for such period, then GEL shall receive 80% of the Gross Profit and 10% shall be payable to the bank and LE shall not receive any of the LE Profit Share until such time as the Deficit Amount is reduced to zero.
   
(d)
Fourth, after the Investment Threshold Date and after the payment to GEL of the GEL Expense Items, 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) shall be paid to GEL as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share.

(e)
After the Investment Threshold Date, if GEL sustains losses, it can recoup those losses by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated.

The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances.  For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above.  The Joint Marketing Agreement had an initial term of three years expiring on August 12, 2014.  In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice.
 
 
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Amendments and Clarifications to the Joint Marketing Agreement – The Joint Marketing Agreement was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

(a)
In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our obligations amount under the Construction and Funding Agreement. In addition, the parties agreed to amend the priority of payments to reflect that, to the extent that there are available funds in a particular month, AFNB shall be paid one-tenth of such funds, provided that we will not participate in available funds until Deficit Amounts added to the Construction and Funding Agreement are paid in full.

(b)
In December 2012, GEL made Operations Payments and other payments to or on behalf of LE in which the aggregate amount exceeded the amount payable to LE in the month of December 2012 under the Joint Marketing Agreement (the “Overpayment Amount”). In December 2012, we entered into an amendment to the Joint Marketing Agreement whereby GEL and Milam agreed that Gross Profits payable to LE would be redirected to GEL as payment for the Overpayment Amount until such Overpayment Amount has been satisfied in full. Such redistributions shall not reduce the distributions of Gross Profit that GEL or Milam are otherwise entitled to under the Joint Marketing Agreement.

(c)
In February 2013, Milam paid a vendor $64,358 (the “Settlement Payment”), which represented amounts outstanding by LE for services rendered at the Nixon Facility plus the vendor’s legal fees.  In addition, Milam and GEL incurred legal fees and expenses related to settling the matter.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed to modify the Joint Marketing Agreement such that, from and after January 1, 2013, the Gross Profit shall be distributed first to GEL, prior to any other distributions or payments to the parties to the Joint Marketing Agreement until GEL has received aggregate distributions as provided in the December 2012 Letter Agreement plus the Settlement Payment and Milam and GEL incurred legal fees and expenses.

(d)
In February 2013, GEL agreed to advance to LE the funds necessary to pay for the actual costs incurred for the scheduled maintenance turnaround at the Nixon Facility and capital expenditures relating to an electronic product meter, lab equipment and certain piping in an amount equal to the actual costs of the refinery turnaround and capital expenditures, not to exceed $840,000 in the aggregate.  In a letter agreement between LE, GEL and Milam dated February 21, 2013, the parties agreed that all amounts advanced by GEL or its affiliates to LE pursuant to the letter agreement shall constitute obligations under the Construction and Funding Agreement.

The principal balance outstanding on the Construction and Funding Agreement was $0 and $5,747,330 at December 31, 2014 and December 31, 2013, respectively.  As a result of LE’s repayment of all amounts due and owing to Milam pursuant to the Construction and Funding Agreement, LE receives up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement and Milam is obligated to release all liens on the Nixon Facility.
 
Results of Operations

We have two reportable business segments: (i) “Refinery Operations” and (ii) “Pipeline Transportation.”  Business activities related to our “Refinery Operations” business segment are conducted at the Nixon Facility and represent approximately 99% of our operations.   Business activities related to our “Pipeline Transportation” business segment are primarily conducted in the Gulf of Mexico through our pipeline assets and leasehold interests in oil and gas properties.  Our “Pipeline Transportation” operations are non-core to our business and represent less than 1% of our operations.  In this “Results of Operations” section, we first review our business on a consolidated basis, and then separately review our “Refinery Operations” business segment.
 
Consolidated Results
 
For our consolidated results, we refer to our financial statement line items in the explanation of our period over period changes in results of operations. We have reclassified certain prior year amounts to conform to our 2014 presentation.  Below are general definitions of what those line items include and represent.
 
Revenue from Operations – Revenue from operations primarily consists of refined petroleum product sales. Revenue from refined petroleum product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements.  Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. Customers assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.
 
 
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Cost of Refined Products Sold – Cost of refined products sold primarily includes purchased crude oil and condensate costs, as well as transportation, freight and storage costs.
 
Refinery Operating Expenses – Refinery operating expenses are the direct operating expenses of the refinery, including direct costs of labor, maintenance materials and services, chemicals and catalysts, utilities and other direct operating expenses of the Nixon Facility.  Refinery operating expenses are considered Services under the Operating Agreement.
 
General and Administrative Expense – General and administrative expenses primarily include corporate costs, such accounting and legal fees, office lease expenses and administrative expenses.
 
Depletion, Depreciation and Amortization – Depletion, depreciation and amortization represent an allocation to expense within the statement of operations of the carrying value of capital and intangible assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset.
 
Other (Income) Expense – Other (income) expense primarily represents income from storage tank rental fees and revenue from FLNG Land, II, Inc., a Delaware corporation (“FLNG”), pursuant to a Master Easement Agreement whereby BDPL is providing FLNG with uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG.
 
Income Tax Benefit (Expense) – Income tax benefit (expense) represents income tax expense for the period comprised of the increase (decrease) during the period for domestic deferred tax assets and liabilities attributable to continuing operations, as well as an income tax provision for federal and state income tax expense related to the current year period.
 
Net Income (Loss) – Represents total revenue from operations less total cost of operations, total other income (expense) and income tax expense, current.
 
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
 
Total Revenue from Operations. For the year ended December 31, 2014 (the “Current Year”), we had total revenue from operations of $387,524,974 compared to total revenue from operations of $409,543,069 for the year ended December 31, 2013 (the “Prior Year”).   The 5% decrease in total revenue from operations was primarily the result of lower refined petroleum product prices in the Current Year compared to the Prior Year. Substantially all of our revenue in the Current Year came from refined petroleum product sales, which generated revenue of $387,304,774, or more than 99% of total revenue from operations, compared to $409,239,747, or more than 99% of total revenue from operations, in the Prior Year.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $363,762,292 for the Current Year compared to $399,101,182 for the Prior Year.  The nearly 9% decrease in cost of refined products sold was primarily the result of a decrease in the average price of crude oil and condensate and operating for 8 fewer days in the Current Year compared to the Prior Year.

Refinery Operating Expenses. Refinery operating expenses in the Current Year remained relatively flat compared to the Prior Year.  We recorded refinery operating expenses of $10,698,023 ($2.77 per barrel of throughput) in the Current Year compared to $10,673,722 ($2.79 per barrel of throughput) in the Prior Year.  Despite operating for fewer days and increasing refinery throughput slightly, refinery operating expenses per barrel of throughput decreased $0.02 for the Current Year compared to the Prior year.  Refinery operating expense represent services provided to us by LEH to manage and operate Blue Dolphin’s assets pursuant to the Operating Agreement with LEH.  See “Part II, Item 8. Financial Statements and Supplementary Data - Note (9), Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement.

General and Administrative Expenses. We incurred general and administrative expenses of $1,427,707 in the Current Year compared to $1,794,053 in the Prior Year.  The more than 20% decrease in general and administrative expenses in the Current Year compared to the Prior Year was primarily related to lower consulting, legal and audit expenses.

Depletion, Depreciation and Amortization.  We recorded depletion, depreciation and amortization expenses of $1,570,962 in the Current Year compared to $1,342,563 in the Prior Year.  The approximate 17% increase in depletion, depreciation and amortization expenses for the Current Year compared to the Prior Year primarily related to depreciable refinery assets placed in service.

Other Income. We recognized $1,400,898 in tank rental and easement revenue in the Current Year compared to $1,155,064 in the Prior Year.  The approximate 21% increase in tank rental and easement revenue in the Current Year compared to the Prior Year was primarily a result of fees received from FLNG Land, II, Inc., a Delaware corporation (“FLNG”), pursuant to a Master Easement Agreement.
 
Net Income (Loss).  For the Current Year, we reported net income of $15,758,756, or an income of $1.51 per share, compared to a net loss of $3,807,129 or a loss of $0.36 per share, for the Prior Year.  The significant increase in net income in the Current Year, which represented an increase of $1.87 per share, was primarily attributable to favorable refining margins, improved product mix, and recognition of a net deferred tax asset.  For the Current Year we recognized a net deferred tax asset of $5,760,106.  The net deferred tax asset was primarily the result of net operating losses (“NOLs”) generated before and after our acquisition of LE in 2012.  See “Part II. Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note (18) Income Taxes” for additional disclosures related to income taxes and our net deferred tax asset.
 
 
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Refining Segment Results

For our refining segment results, we refer to key operational data in the explanation of our period over period changes in results of operations. Below are general definitions of what those items include and represent.

Operating Days – The number of days in a calendar period in which the Nixon Facility operated.  Downtime is excluded from operating days.

Downtime – Scheduled or unscheduled periods in which the Nixon Facility is not operable.  Downtime may be required for a variety of reasons, including maintenance, inspection and equipment repair, voluntary regulatory compliance measures, and cessation or suspension by regulatory authorities.

Total Refinery Throughput – Refers to the volume processed as input through the Nixon Facility.  Refinery throughput includes crude oil and condensate and other feedstocks.

Total Refinery Production – Refers to the volume processed as output through the Nixon Facility.  Refinery production includes finished petroleum products, such as jet fuel, and intermediate petroleum products, such as naphtha, LPG and atmospheric gas oil.

Fuel and Energy Losses – Represents crude oil and condensate volumes used to power the Nixon Facility and energy losses that occur as part of normal refinery operations, such as evaporation from oil-water separators and small steam or condensate leaks.

Capacity Utilization Rate –A percentage measure that indicates the amount of available capacity that is being used at the Nixon Facility. The rate is calculated by dividing total refinery throughput on a bpd basis or total refinery production on a bpd basis by the total capacity of the Nixon Facility, which is currently 15,000 bpd.

Refinery Operating Income – Refinery operating income is a function of refined petroleum product sales less cost of refined petroleum products sold and refinery operating expenses.

Refinery Operating Income Per Barrel Sold– Refinery operating income per barrel sold is a general indication of the amount, on a per barrel basis, for which the Nixon Facility was able to sell its refined petroleum products above its cost of refined petroleum products sold and refinery operating expenses.  Refinery operating income per barrel sold is calculated by subtracting cost of refined products sold and refinery operating expenses from refined petroleum product sales and dividing the difference by total refined petroleum product sales (bbl) for the respective periods presented.

Earnings Before Interest, Income Taxes and Depreciation (“EBITDA”) – Earnings is adjusted for: (i) income taxes and (ii) interest income (expense), depreciation and amortization. We exclude interest expense (or income) and other expenses or income not pertaining to the operations of our segments from EBITDA.
 
Remainder of Page Intentionally Left Blank
 
 
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Key Operational Metrics

The Nixon Facility, which was refurbished and began operations in February 2012, has been operating for approximately three years.  Following are key operational metrics for the Nixon Facility:
 
   
Year Ended December 31,
 
   
2014
   
2013
 
             
Operating Days
    333       341  
                 
Downtime
    32       24  
                 
Total refinery throughput
               
bbls
    3,862,351       3,822,128  
bpd
    11,599       11,209  
                 
Total refinery production
               
bbls
    3,788,710       3,743,482  
bpd
    11,378       10,978  
                 
Total refined petroleum product sales
               
bbls
    3,779,677       3,709,294  
                 
Fuel and energy losses
               
bbls
    73,641       78,646  
bpd
    221       231  
                 
Capacity utilization rate
               
refinery throughput
    77.3 %     74.7 %
refinery production
    75.9 %     73.2 %
                 
Refinery operating income(1)
  $ 12,844,459     $ (535,157 )
per bbl sold(1)
  $ 3.40     $ (0.14 )
                 
EBITDA(1)
  $ 13,821,685     $ 552,859  
 ______________________
 
(1)  
See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -- Non-GAAP Performance Measures” of this report for a reconciliation of this non-GAAP financial measure to the applicable GAAP financial measure within our consolidated balance sheets and/or statements of operations.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Operating Days.  The Nixon Facility operated for a total of 333 days during the year ended December 31, 2014 (the “Current Year”) compared to a total of 341 days during the year ended December 31, 2013 (the “Prior Year”).  This represented 8 fewer operating days in the Current Year compared to the Prior Year, which related to downtime.

Downtime. The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations. Downtime may result in lost margin opportunity, increased maintenance expense, and a reduction in cash available for payment of our obligations.  The Nixon Facility experienced 32 days of downtime in the Current Year compared to 24 days of downtime in the Prior Year.  This represented 8 more days of downtime in the Current Year compared to the Prior Year.  Downtime during the Current Year primarily related to a planned maintenance turnaround and repair of an overhead accumulator. Downtime during the Prior Year primarily related to a planned maintenance turnaround.

Total Refinery Throughput.  For the Current Year, the Nixon Facility processed 3,862,351 bbls, or 11,599 bpd, of crude oil and condensate compared to 3,822,128 bbls, or 11,209 bpd, of crude oil and condensate for the Prior Year.  Despite operating for fewer days, refinery throughput increased slightly for the Current Year compared to the Prior year, rising by 40,223 bbls, or 390 bpd, as the Nixon Facility capitalized on lower crude oil and condensate acquisition costs.
 
 
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Total Refinery Production.  For the Current Year, the Nixon Facility processed 3,788,710 bbls, or 11,378 bpd, of refined petroleum products compared to 3,743,482 bbls, or 10,978 bpd, of refined petroleum products for the Prior Year.  Despite operating for fewer days, refinery production increased slightly for the Current Year compared to the Prior Year, rising 45,228 bbls, or 400 bpd, as the Nixon Facility increased throughput volumes to capitalize on lower crude oil and condensate acquisition costs and increased jet fuel production.

Fuel and Energy Losses.  For the Current Year, fuel and losses at the Nixon Facility were 73,641 bbls, or 221 bpd, compared to 78,646 bbls, or 231 bpd, for the Prior Year.  The nominal decrease in fuel and losses of 5,005 bbls, or 9 bpd, was the result of operational efficiency improvements.

Capacity Utilization Rate.  The capacity utilization rate for refinery throughput for the Current Year was 77.3% compared to 74.7% for the Prior Year, reflecting a nominal increase of 2.6%.  The capacity utilization rate for refinery production for the Current Year was 74.7% compared to 75.9% for the Prior Year, reflecting a nominal increase of 2.7%.  The increase in capacity utilization rates for refinery throughput and refinery production related to increases in throughput and production volumes as the Nixon Facility capitalized on lower crude oil and condensate acquisition costs, as well as an increase in the production of jet fuel.

Refinery Operating Income.  For the Current Year, the Nixon Facility had a refinery operating income of $12,884,459 compared to a negative refinery margin of $535,157 for the Prior Year.  Refinery operating income increased by $13,379,616 for the Current Year compared to the Prior Year.  The significant increase in refinery operating income between the periods was the result of lower crude oil and condensate acquisition costs and improved product mix as a result of increased jet fuel production.

Refinery Operating Income Per Barrel Sold.  For the Current Year, the Nixon Facility had a refinery operating income per barrel sold of $3.40 compared to a negative refinery operating income per barrel sold of $0.14 for the Prior Year.  This represented an increase in refinery operating income per barrel sold of $3.54 for the Current Year compared to the Prior Year.  The significant increase in refinery operating income per barrel sold between the periods was the result of lower crude oil and condensate acquisition costs and improved product mix as a result of increased jet fuel production.

EBITDA.  For the Current Year, our “Refinery Operations” business segment had EBITDA of $13,821,685 compared to EBITDA of $552,859 for the Prior Year.  This represented an increase in EBITDA of $13,268,826 for the Current Year compared to the Prior Year.  The significant increase in EBITDA between the periods was the result of lower crude oil and condensate acquisition costs and improved product mix as a result of increased jet fuel production.

Refined Petroleum Product Sales Summary

All of our refined petroleum products are currently sold in the United States. The following tables summarize total refined petroleum product sales:
 
   
Years Ended December 31,
 
   
2014
   
2013
 
                         
Atmospheric gas oil
  $ 96,027,339       24.8 %   $ 101,955,402       24.9 %
Naphtha
    89,700,423       23.2 %     103,980,651       25.4 %
Jet fuel
    88,479,458       22.8 %     20,048,594       4.9 %
NRLM
    62,729,476       16.2 %     182,513,228       44.6 %
Oil-based mud blendstock
    49,662,414       12.8 %     -       0.0 %
LPG mix
    705,664       0.2 %     499,277       0.1 %
Reduced crude
    -       0.0 %     242,595       0.1 %
                                 
Total refined petroleum product sales
  $ 387,304,774       100.0 %   $ 409,239,747       100.0 %
 
 
 
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On May 31, 2014, the Nixon Facility ceased production of NRLM, a transportation-related diesel fuel product.  On June 1, 2014, the Nixon Facility began producing oil-based mud blendstock, a non-transportation lubricant blend product.  The shift in product slate from NRLM to oil-based mud blendstock was the result of the Environmental Protection Agency’s (the “EPA’s”) phased-in requirements for small refineries to reduce the sulfur content in transportation-related diesel fuel, such as NRLM, to a maximum of 15 ppm sulfur by June 1, 2014.  “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s recently implemented fuel quality standards, and integration of such a unit generally requires additional permitting and significant capital expenditures.  The Nixon Facility could produce and sell higher ppm sulfur diesel as a feedstock to other refineries and blenders in the United States and as a finished petroleum product to other countries.

The Nixon Facility began producing jet fuel in late 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.

Refined Petroleum Product Economic Hedges

Operation cost within our refining segment includes the effect of economic hedges on our refined petroleum product inventories.  For the Current Year, our refining segment recognized a realized gain of $3,327,921 and an unrealized gain of $488,950.  For the Prior Year, our refining segment recognized a realized loss of $246,210 and an unrealized gain of $143,050.

Non-GAAP Performance Measures

Refinery operating income, refinery operating income per barrel sold, and EBITDA are non-GAAP performance measures used by management to assess our operating results and the effectiveness of our business segments. Calculations of refinery operating income, refinery operating income per barrel sold, and EBITDA may differ from similar calculations of other companies in our industry, thereby limiting its usefulness to investors as a comparative measure.
 
Refinery Operating Income and Refinery Operating Income Per Barrel Sold.  The following table provides a reconciliation of refinery operating income and refinery operating income per barrel sold to refined petroleum product sales, cost of refined petroleum products sold, and refinery operating expenses for the periods indicated. For a reconciliation of refined petroleum product sales to total revenue from operations for our consolidated operations, see “Part II, Item 8. Financial Statements and Supplementary Data – Consolidated Statements of Operations” of this report.
 
   
December 31,
 
   
2014
   
2013
 
             
Total refined petroleum product sales
  $ 387,304,774     $ 409,239,747  
Less:
               
Cost of refined petroleum products sold
    (363,762,292 )     (399,101,182 )
Refinery operating expenses
    (10,698,023 )     (10,673,722 )
      (374,460,315 )     (409,774,904 )
                 
Refinery operating income
  $ 12,844,459     $ (535,157 )
                 
Total refined petroleum product sales (bbls)
    3,779,677       3,709,294  
                 
Refinery operating income per bbl sold
  $ 3.40     $ (0.14 )
 
 
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EBITDA.  EBITDA should be considered in conjunction with net income (loss) and other performance measures such as operating cash flows.  Following is a reconciliation of EBITDA, capital expenditures, and identifiable assets by business segment for the year ended December 31, 2014 (and at December 31, 2014) and the year ended December 31, 2013 (and at December 31, 2013):
 
   
Year Ended December 31, 2014
 
   
Segment
             
   
Refinery
   
Pipeline
   
Corporate &
       
   
Operations
   
Transportation
   
Other
   
Total
 
Revenue
  $ 387,304,774     $ 220,200     $ -     $ 387,524,974  
Less:  Operation cost(1)
    (374,613,154 )     (483,262 )     (1,242,466 )     (376,338,882 )
Other non-interest income
    1,130,065       270,833       -       1,400,898  
EBITDA
  $ 13,821,685     $ 7,771     $ (1,242,466 )   $ 12,586,990  
                                 
Depletion, depreciation and amortization
                            (1,570,962 )
Interest expense, net
                            (844,850 )
                                 
Income before income taxes
                          $ 10,171,178  
                                 
Capital expenditures
  $ 1,720,156     $ -     $ -     $ 1,720,156  
                                 
Identifiable assets(2)
  $ 50,950,050     $ 3,028,719     $ 6,428,388     $ 60,407,157  

(1) 
Operation cost within the “Refinery Operations” and “Pipeline Transportation” segments includes related general, administrative, and accretion expenses.  Operation cost within “Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(2) 
Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.
 
   
Year Ended December 31, 2013
 
   
Segment
             
   
Refinery
   
Pipeline
   
Corporate &
       
   
Operations
   
Transportation
   
Other
   
Total
 
Revenue
  $ 409,239,747     $ 303,322     $ -     $ 409,543,069  
Less:  Operation cost(1)
    (409,800,285 )     (524,051 )     (1,652,160 )     (411,976,496 )
Other non-interest income
    1,113,397       41,667       -       1,155,064  
EBITDA
  $ 552,859     $ (179,062 )   $ (1,652,160 )   $ (1,278,363 )
                                 
Depletion, depreciation and amortization
                            (1,342,563 )
Interest expense, net
                            (1,096,948 )
                                 
Loss before income taxes
                          $ (3,717,874 )
                                 
Capital expenditures
  $ 1,477,729     $ -     $ -     $ 1,477,729  
                                 
Identifiable assets(2)
  $ 54,470,723     $ 2,399,467     $ 809,311     $ 57,679,501  

(1) 
Operation cost within the “Refinery Operations” and “Pipeline Transportation” segments includes related general, administrative, and accretion expenses.  Operation cost within “Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense.
(2)
Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets.
 
 
34

 

Liquidity and Capital Resources

Sources and Uses of Cash

At December 31, 2014 and 2013, we had cash and cash equivalents of $1,293,233 and $434,717, respectively.  Since our reverse acquisition of LE in 2012, in which we acquired the Nixon Facility, we have relied on our profit share distribution under the Joint Marketing Agreement, LEH and GEL to fund our working capital requirements.  During months in which we receive no profit share distribution under the Joint Marketing Agreement, LEH and/or GEL may, but are not required to, fund our operating losses. As of December 31, 2014, the working capital amount funded by LEH and GEL was $1,174,168 and $0, respectively.  Amounts funded by LEH are reflected in accounts payable, related party in our consolidated balance sheets. Amounts previously funded by GEL were reflected as Deficit Amount under the Construction and Funding Agreement.

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

Cash Flow

Our cash flow from operations for the periods indicated was as follows:
 
   
Years Ended December 31,
 
   
2014
   
2013
 
             
Cash flow from operations
           
Adjusted income (loss) from continuing operations
  $ 11,425,857     $ (2,287,900 )
Change in assets and current liabilities
    (4,247,678 )     3,311,718  
                 
Total cash flow from operations
    7,178,179       1,023,818  
                 
Cash inflows (outflows)
               
Proceeds from issuance of long-term debt
    -       5,750,611  
Payments on long term debt
    (6,226,521 )     (5,274,106 )
Capital expenditures
    (1,720,156 )     (1,477,729 )
Proceeds from sale of assets
    -       201,000  
Proceeds from notes payable
    2,000,000       15,032  
Payments on notes payble
    (372,986 )     (224,805 )
                 
Total cash outflows
    (6,319,663 )     (1,009,997 )
                 
Total change in cash flows
  $ 858,516     $ 13,821  
 
 
35

 

For the Current Year, we experienced positive cash flow from operations of $7,178,179 compared to positive cash flow from operations of $1,023,818 for the Prior Year, which represented an increase in cash flow from operations of $6,154,361 for the Current Year compared to the Prior Year.  The improvement in cash flow from operations was primarily the result of improved profitability in the Current Year as income from operations increased to $9,619,530 compared to a loss from operations of $3,775,990 for the Prior Year, an improvement of $13,395,520.  The improvement in cash flow from operations was robust enough to offset a moderate increase in Current Year capital spending as well as a very significant reduction in Current Year cash flow from financing activities.  Cash flow from financing activities declined as the aforementioned improvement in profitability enabled us to repay the Prior Year's outstanding balance under the Construction and Funding Agreement in full.

Working Capital

We had negative working capital of $3,200,991, consisting of $14,682,657 in total current assets and $17,883,648 in total current liabilities, at December 31, 2014. Comparatively, we had negative working capital of $7,929,834, consisting of $20,488,953 in total current assets and $28,418,787 in total current liabilities, at December 31, 2013.  The $4,728,843 improvement in working capital from the prior year primarily stemmed from improved profitability in 2014, which enabled reductions in accounts payable of $8,413,362 and accounts payable, related party of $2,485,172.

Capital Spending

Capital expenditures in the Current Year totaled $1,720,156 compared to $1,477,729 in the Prior Year.  Capital spending primarily related to investments in the Nixon Facility.  We expect to fund additional capital expenditures at the Nixon Facility primarily through cash from operations or other borrowings.   On May 2, 2014, Lazarus Refining & Marketing, LLC (“LRM”) entered into a loan and security agreement with Sovereign Bank, a Texas state bank (“Sovereign”), for a term loan facility in the aggregate amount of $2.0 million (the “Sovereign Loan”).  The proceeds of the Sovereign Loan are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. On August 7, 2014, LRM also entered into a 36 month “build-to-suit” capital lease with for the purchase of new boiler equipment for the Nixon Facility. The boiler equipment was delivered in December 2014 and placed in service during the first quarter of 2015.

Indebtedness

The principal balance outstanding on the Refinery Note was $8,648,980 and $9,057,937 at December 31, 2014 and 2013, respectively. The principal balance outstanding on the Sovereign Loan was $1,638,898 and $0 at December 31, 2014 and 2013, respectively. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at December 31, 2014 and 2013. The principal balance outstanding on a capital lease was $466,401 and $0 at December 31, 2014 and 2013, respectively. See “Part II, Item 8. Financial Statements and Supplementary Data - Note (13) Long-Term Debt” of this report for additional disclosures related to our long-term debt obligations.

Critical Accounting Policies

Long Lived Assets
 
Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are included as operating expenses under the Operating Agreement and covered by LEH (see “Part II, Item 8. Financial Statements and Supplementary Data – Note (9) Accounts Payable, Related Party” in this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.
 
Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations.
 
For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service.
 
 
36

 
 
Management has evaluated the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the years ended December 31, 2014 and 2013.
 
Pipelines and Facilities Assets. We record pipelines and facilities at the lower of cost or net realizable value.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.
 
Construction in Progress. Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service.
 
Revenue Recognition
 
We sell various refined petroleum products including jet fuel, naphtha, distillates, and atmospheric gas oil. Revenue from refined petroleum product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.
 
Customers assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined petroleum products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.
 
Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in other income.  Land easement revenue is recorded monthly and included in other income.

Asset Retirement Obligations

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

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

We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating or disposing of our offshore platform, pipeline systems and related onshore facilities, as well as plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis.
 
 
37

 

Income Taxes

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

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

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

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

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (18) Income Taxes” of this report for further information related to income taxes.
 
Recently Adopted Accounting Guidance

The guidance issued by the FASB during the year ended December 31, 2014 is not expected to have a material effect on our consolidated financial statements.
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Crude oil refining is primarily a margins-based business where both crude oil and refined petroleum products are commodities with prices that can fluctuate independently for short periods due to supply, demand, transportation and other factors. The spread between the cost of our feedstocks and the sales price of refined petroleum products is the primary factor affecting our operations, liquidity and financial condition. Our crude oil and condensate 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, and other refined petroleum products. Supply and demand for these products depend, among other things, on changes in domestic and foreign economies; weather conditions; domestic and foreign political affairs; production levels; availability of imports and exports; marketing of competitive fuels; and government regulation.

Under our inventory risk management policy, Genesis may, but is not required to, use derivative instruments as certain of our refined petroleum product inventories exceed certain thresholds in an effort to reduce our commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.
 
At December 31, 2014, we performed a sensitivity analysis to determine the impact of an increase in the market price of commodity contracts for our economic hedges. Based on this sensitivity analysis, we determined that an increase of $1.00 per barrel in commodity contracts held at December 31, 2014 would increase unrealized loss by approximately $115,000.
 
 
38

 

Interest Rate Risk

We are exposed to interest rate volatility with regard to existing variable rate debt that is tied to movements in the U.S. Prime Rate. At December 31, 2014, we had $10,287,878 of variable interest debt with a weighted average interest rate at year end of approximately 5.75%.  At December 31, 2014, we performed a sensitivity analysis to determine the impact of an increase in interest rates. Based on this sensitivity analysis, we determined that an increase of 1% in our average floating interest rates at December 31, 2014 would increase interest expense by approximately $102,879 per year.
 
Remainder of Page Intentionally Left Blank
 
 
39

 

 
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
Index to Financial Statements
 
 
 
Report of Independent Registered Public Accounting Firm   41
     
Consolidated Balance Sheets at December 31, 2014 and 2013   42
     
Consolidated Statements of Operations for the Years Ended December 31, 2014 and 2013   43
     
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2014 and 2013   44
     
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014 and 2013   45
     
Notes to Consolidated Financial Statements   46
 

Remainder of Page Intentionally Left Blank
 
 
40

 


 

 
Report of Independent Registered Public Accounting Firm


The Board of Directors and
Stockholders of Blue Dolphin Energy Company
 
We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and its subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and its subsidiaries as of December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ UHY LLP
____________________
 UHY LLP
Sterling Heights, Michigan
March 31, 2015
 
 
41

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Balance Sheets
 
   
December 31,
 
   
2014
   
2013
 
 ASSETS
           
 CURRENT ASSETS
           
 Cash and cash equivalents
  $ 1,293,233     $ 434,717  
 Restricted cash
    1,008,514       327,388  
 Accounts receivable
    8,340,303       13,487,106  
 Prepaid expenses and other current assets
    771,458       333,683  
 Deposits
    68,498       1,219,660  
 Inventory
    3,200,651       4,686,399  
 Total current assets
    14,682,657       20,488,953  
                 
 Total property and equipment, net
    37,371,075       36,388,666  
 Surety bonds
    1,642,000       -  
 Debt issue costs, net
    479,737       498,536  
 Trade name
    303,346       303,346  
 Deferred tax assets, net
    5,928,342       -  
                 
 TOTAL ASSETS
  $ 60,407,157     $ 57,679,501  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 CURRENT LIABILITIES
               
 Accounts payable
  $ 12,370,179     $ 20,783,541  
 Accounts payable, related party
    1,174,168       3,659,340  
 Notes payable
    -       11,884  
 Asset retirement obligations, current portion
    85,846       107,388  
 Accrued expenses and other current liabilities
    2,783,704       1,600,444  
 Interest payable, current portion
    56,039       40,272  
 Long-term debt, current portion
    1,245,476       2,215,918  
 Deferred tax liabilities
    168,236       -  
 Total current liabilities
    17,883,648       28,418,787  
                 
 Long-term liabilities:
               
 Asset retirement obligations, net of current portion
    1,780,924       1,490,273  
 Deferred revenues and expenses
    691,525       -  
 Long-term debt, net of current portion
    10,808,803       13,889,349  
 Long-term interest payable, net of current portion
    1,274,789       1,767,381  
 Total long-term liabilities
    14,556,041       17,147,003  
                 
 TOTAL LIABILITIES
    32,439,689       45,565,790  
                 
 Commitments and contingencies (Note 22)
               
                 
 STOCKHOLDERS' EQUITY
               
Common stock ($0.01 par value, 20,000,000 shares authorized;10,599,444 and 10,580,973 shares issued at December 31, 2014 and 2013, respectively)
    105,995       105,810  
 Additional paid-in capital
    36,718,781       36,623,965  
 Accumulated deficit
    (8,057,308 )     (23,816,064 )
 Treasury stock, 150,000 shares at cost
    (800,000 )     (800,000 )
 Total stockholders' equity
    27,967,468       12,113,711  
                 
 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
  $ 60,407,157     $ 57,679,501  
 
See accompanying notes to consolidated financial statements. 
 
 
42

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Statements of Operations
 
   
Years Ended December 31,
 
   
2014
   
2013
 
REVENUE FROM OPERATIONS
           
Refined product sales
  $ 387,304,774     $ 409,239,747  
Pipeline operations
    220,200       303,122  
Oil and gas sales
    -       200  
Total revenue from operations
    387,524,974       409,543,069  
                 
COST OF OPERATIONS
               
Cost of refined products sold
    363,762,292       399,101,182  
Refinery operating expenses
    10,698,023       10,673,722  
Pipeline operating expenses
    208,037       163,163  
Lease operating expenses
    26,428       67,923  
General and administrative expenses
    1,427,707       1,794,053  
Depletion, depreciation and amortization
    1,570,962       1,342,563  
Abandonment expense
    -       63,767  
Accretion expense
    211,995       112,686  
                 
Total cost of operations
    377,905,444       413,319,059  
                 
Income (loss) from operations
    9,619,530       (3,775,990 )
                 
OTHER INCOME (EXPENSE)
               
Tank rental and easement revenue
    1,400,898       1,155,064  
Interest and other income
    47,522       3,105  
Interest expense
    (892,372 )     (1,100,053 )
Loss on disposal of property and equipment
    (4,400 )     -  
Total other income
    551,648       58,116  
                 
Income (loss) before income taxes
    10,171,178       (3,717,874 )
                 
Income tax benefit (expense)
    5,587,578       (89,255 )
                 
Net income (loss)
  $ 15,758,756     $ (3,807,129 )
                 
Income (loss) per common share
               
Basic
  $ 1.51     $ (0.36 )
                 
Diluted
  $ 1.51     $ (0.36 )
                 
Weighted average number of common shares outstanding:
 
Basic
    10,441,464       10,445,883  
Diluted
    10,441,464       10,445,883  
 
See accompanying notes to consolidated financial statements.
 
 
43

 
 
Blue Dolphin Energy Company & Subsidiaries
Consolidated Statements of Stockholders’ Equity
 
   
Common Stock
                         
               
Additional
                     
Total
 
               
Paid-In
   
Accumulated
   
Treasury Stock
   
Stockholders’
 
   
Shares Issued
   
Par Value
   
Capital
   
Deficit
   
Shares
   
Cost
   
Equity
 
                                           
Balance at December 31, 2012
    10,563,297       105,633       36,524,142       (20,008,935 )     -       -       16,620,840  
                                                         
Common stock issued for services
    17,676       177       99,823       -       -       -       100,000  
Treasury stock acquired
    -       -       -       -       (150,000 )     (800,000 )     (800,000 )
Net loss
    -       -       -       (3,807,129 )     -       -       (3,807,129 )
                                                         
Balance at December 31, 2013
    10,580,973     $ 105,810     $ 36,623,965     $ (23,816,064 )     (150,000 )   $ (800,000 )   $ 12,113,711  
                                                         
Common stock issued for services
    18,471       185       94,816       -       -       -       95,001  
Treasury stock acquired
    -       -       -       -       -       -       -  
Net income
    -       -       -       15,758,756       -       -       15,758,756  
                                                         
Balance at December 31, 2014
    10,599,444     $ 105,995     $ 36,718,781     $ (8,057,308 )     (150,000 )   $ (800,000 )   $ 27,967,468  
 
See accompanying notes to consolidated financial statements.
 
Remainder of Page Intentionally Left Blank
 
 
44

 
 
Blue Dolphin Energy Company & Subsidiaries 
Consolidated Statements of Cash Flows
 
   
Years Ended December 31,
 
   
2014
   
2013
 
OPERATING ACTIVITIES
           
   Net income (loss)
  $ 15,758,756     $ (3,807,129 )
   Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
               
Depletion, depreciation and amortization
    1,570,962       1,342,563  
Unrealized gain on derivatives
    (488,950 )     (143,050 )
Deferred taxes
    (5,760,106 )     -  
Amortization of debt issue costs
    33,799       33,800  
Amortization of intangible assets
    -       9,463  
Accretion expense
    211,995       112,686  
Abandonment costs incurred
    -       63,767  
Common stock issued for services
    95,001       100,000  
Loss on disposal of assets
    4,400       -  
Changes in operating assets and liabilities
               
Restricted cash
    (681,126 )     (237,795 )
Accounts receivable
    5,146,803       1,111,649  
Prepaid expenses and other current assets
    (437,775 )     (105,369 )
Deposits and other assets
    (505,838 )     16,787  
Inventory
    1,485,748       (2,385,707 )
Accounts payable, accrued expenses and other liabilities
    (6,770,318 )     2,846,834  
Accounts payable, related party
    (2,485,172 )     2,065,319  
Net cash provided by operating activities
    7,178,179       1,023,818  
                 
INVESTING ACTIVITIES
               
Capital expenditures
    (1,720,156 )     (1,477,729 )
Proceeds from sale of assets
    -       201,000  
Net cash used in investing activities
    (1,720,156 )     (1,276,729 )
                 
FINANCING ACTIVITIES
               
Proceeds from issuance of debt
    -       5,750,611  
Payments on long-term debt
    (6,226,521 )     (5,274,106 )
Proceeds from notes payable
    2,000,000       15,032  
Payments on notes payable
    (372,986 )     (224,805 )
Net cash provided by (used in) financing activities
    (4,599,507 )     266,732  
Net increase in cash and cash equivalents
    858,516       13,821  
                 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    434,717       420,896  
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 1,293,233     $ 434,717  
                 
Supplemental Information:
               
Non-cash operating activities
               
Reduction in accounts receivable in exchange for treasury stock received
  $ -     $ 800,000  
Surety bond funded by seller of pipeline interest
  $ 850,000     $ -  
Non-cash investing and financing activities:
               
New asset retirement obligations
  $ 300,980     $ -  
Changes in estimates of existing ARO obligations
  $ -     $ 592,415  
Financing of capital expenditures via capital lease
  $ 536,635     $ -  
Accrued services payable converted to common stock
  $ -     $ 50,000  
Interest paid
  $ 1,369,197     $ 791,536  

See accompanying notes to consolidated financial statements.
 
 
45

 
 
Notes to Consolidated Financial Statements
 
(1)
Organization

Nature of Operations

Blue Dolphin Energy Company (http://www.blue-dolphin-energy.com, referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) is primarily an independent refiner and marketer of petroleum products.  Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, 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, which are considered non-core to our business. See “Note (4) Business Segment Information” of this report for further discussion of our business segments.

Structure and Management

We were formed as a Delaware corporation in 1986.  In connection with our reverse acquisition of Lazarus Energy, LLC (“LE”) in 2012, whereby we acquired the Nixon Facility, we:

(i)  
issued 8,426,456 shares of our common stock, par value $0.01 per share (the “Common Stock”) to Lazarus Energy Holdings, LLC (“LEH”) as consideration.  As a result, LEH, our controlling shareholder, owns approximately 81% of our Common Stock.  Jonathan P. Carroll, Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH; and
(ii)  
entered into a Management Agreement dated and effective February 12, 2012 with LEH.  Pursuant to the Management Agreement, LEH manages our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business.  On May 12, 2014, the Management Agreement was amended to: (a) extend the term to August 12, 2015, and (b) change the name of the agreement from “Management Agreement” to “Operating Agreement” (the “Operating Agreement”).

Our operations are conducted directly and indirectly through our primary operating subsidiaries, as follows:

·
LE, a Delaware limited liability company (petroleum processing assets);
·
Lazarus Refining & Marketing, LLC, a Delaware limited liability company (petroleum storage and terminaling) (“LRM”);
·
Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations) (“BDPL”);
·
Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);
·
Blue Dolphin Services Co., a Texas corporation (administrative services);
·
Blue Dolphin Exploration Company, a Delaware corporation (exploration and production investments) (“BDEX”); and
·
Petroport, Inc., a Delaware corporation (inactive).
 
(2)
Basis of Presentation

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

 (3)
Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and notes are representations of management who is responsible for its integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements.
 
 
46

 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements (Continued)
 
Use of Estimates

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

Cash and Cash Equivalents

Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.  Cash and cash equivalents amounted to $1,293,233 and $434,717 at December 31, 2014 and 2013, respectively.

Restricted Cash

On September 29, 2008, LE entered into a certain Loan Agreement (the “Loan Agreement”) with First International Bank (“FIB”) as evidenced by that certain promissory note, of even date with the Loan Agreement, in the original principal amount of $10.0 million (the “Refinery Note”).  In October 2011, the Loan Agreement was acquired by American First National Bank (“AFNB”).  Restricted cash represents a payment reserve account to be drawn upon by AFNB in the event that we fail to make any payment in a timely manner as required under the Loan Agreement.  Restricted cash was $1,008,514 and $327,388 at December 31, 2014 and 2013, respectively.

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

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

Concentration of Risk

Bank Accounts

Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor.  We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $1,113,977 and $77,388 at December 31, 2014 and 2013, respectively.

Significant Customers

Customers of our refined 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, including month-to-month, six months, and up to five year terms in place with most of our customers.  Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products.  See “Note (16) Concentration of Risk” of this report for additional disclosures related to significant customers.
 
 
47

 

Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements (Continued)
 
Inventory

The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products. Inventory reflected for crude oil and condensate is nominal and represents line fill. Because refined petroleum products are commodities, we have no control over the changing market value of these inventories. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method.  If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated impairment expense.  See “Note (7) Inventory” of this report for additional disclosures related to our inventory.

Price-Risk Management Activities

Under our inventory risk management policy, Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce our commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand-alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Although such hedge positions are direct contractual obligations of Genesis and not us, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statement of operations.  See “Note (21) Refined Petroleum Products Inventory Risk Management” of this report for additional disclosures related to our inventory risk management policy.

Property and Equipment

Refinery and Facilities

Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included as operating expenses under the Operating Agreement with LEH (see “Note (9) Accounts Payable Related Party” of this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances.

Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations.

For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service.

Management has evaluated the FASB ASC guidance related to asset retirement obligations (“AROs”) for our refinery and facilities. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We did not record any impairment of our refinery and facilities for the years ended December 31, 2014 and 2013.

Oil and Gas Properties

We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method.  Our Gulf of Mexico oil and gas properties had no production during the years ended December 31, 2014 and 2013.  All leases associated with our Gulf of Mexico oil and gas properties have expired.

Pipelines and Facilities

We record pipelines and facilities at the lower of cost or net realizable value.  Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom.
 
 
48

 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements (Continued)
 
Construction in Progress

Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service.

See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress.

Intangibles – Other

We recognized trade name in connection with our reverse acquisition of LE in 2012. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014.

Debt Issue Costs

We have debt issue costs related to certain facilities debt. Debt issue costs are cap