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, 2012
 
or
 
¨
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 ¨ 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 ¨ No þ

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

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

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 ¨ Accelerated filer ¨ Non-accelerated filer ¨ 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
 
Aggregate market value of voting stock held by non-affiliates of the registrant as of June 30, 2012 was approximately $14,361,145 million based on the closing price of $7.95 per share on the OTCQX.
 
Number of shares of Common Stock outstanding as of March 29, 2012
10,563,297



 
 

 
 
FORM 10-K REPORT INDEX
 
PART I      
         
ITEM 1. BUSINESS     5  
ITEM 1A. RISK FACTORS     21  
ITEM 1B. UNRESOLVED STAFF COMMENTS     29  
ITEM 2. PROPERTIES     29  
ITEM 3. LEGAL PROCEEDINGS     30  
ITEM 4. MINE SAFETY DISCLOSURES     30  
           
PART II        
           
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES     31  
ITEM 6. SELECTED FINANCIAL DATA     32  
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     32  
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     43  
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     44  
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     83  
ITEM 9A. CONTROLS AND PROCEDURES     83  
ITEM 9B. OTHER INFORMATION     84  
           
PART III        
           
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE     85  
ITEM 11. EXECUTIVE COMPENSATION     89  
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS     91  
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE     92  
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES     93  
           
PART IV        
           
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES     94  
           
SIGNATURES     100  
 
 
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 otherwise 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:
 
the potential reorganization of Blue Dolphin from a publicly traded “C” corporation to a publicly traded master limited partnership;
fluctuations of crude oil inventory costs and refined petroleum products inventory prices and their effect on our refining margins;
our dependence on Genesis Energy, LLC (“Genesis”) and its affiliates for financing, sources of crude oil inventory and marketing of our refined petroleum products;
the positive or negative effects of Genesis’ hedging of our refined petroleum products and crude oil inventory;
our dependence on Lazarus Energy Holdings, LLC ("LEH") for management of the Nixon Facility;
dependence on a small number of customers for a large percentage of our revenues;
our ability to generate sufficient funds from operations or obtain financing from other sources;
declaration of an event of default related to our long-term indebtedness;
failure to comply with other forbearance agreements relating to our long-term indebtedness;
potential downtime of the Nixon refinery for maintenance and repairs;
access to less than desired levels of crude oil for processing at our crude oil and condensate processing facility located in Nixon, Texas;
operating hazards such as fires and explosions;
insurance coverage limitations;
environmental costs and liabilities associated with our operations;
retention and recruitment of key employees;
performance of third-party operators of our oil and gas properties;
costs of abandoning our pipelines and oil and gas properties;
 
 
local and regional events that may negatively affect our assets;
competition from larger companies;
acquisition expenses and integration difficulties; and
compliance with environmental and other regulations, including greenhouse gas emissions regulations, the effects of the Renewable Fuels Standard program and oxygenate blending requirements.

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

 

Remainder of Page Intentionally Left Blank
 




The Company

Blue Dolphin Energy Company (www.blue-dolphin-energy.com), a Delaware corporation (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”) was formed in 1986 as a holding company. We conduct substantially all of our operations through our wholly-owned subsidiaries. We acquired LE, the primary asset of which is the Nixon Facility, from LEH in February 2012 (the “LE Acquisition”). The transaction resulted in a change in control of Blue Dolphin with LEH owning approximately eighty percent (80%) of our issued and outstanding common stock, par value $0.01 per share (the "Common Stock"). The combined company operates under the name Blue Dolphin Energy Company. The LE Acquisition was accounted for as a “reverse acquisition.” Under reverse acquisition accounting LE (the legal subsidiary) was treated as the accounting parent (acquirer) and Blue Dolphin (the legal parent) was treated as the accounting subsidiary (acquiree). Accordingly, the financial statements subsequent to the date of the transaction are presented as the continuation of LE.
 
As a result of our acquisition of LE and Lazarus Refining & Marketing, LLC (“LRM”) in October 2012, we are primarily an independent refiner and marketer of petroleum products. As part of our refining business segment we also conduct petroleum storage and terminaling operations through LRM. These operations involve the storage of petroleum under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties.

Refining Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel, asphalt and other products. The typical refining process for most refineries involves numerous stages to create final products. However, the Nixon Facility currently engages in the first stage of the refining process. Refining is primarily a margin-based business where the crude oil and other feedstocks and refined products are commodities with fluctuating prices. In order to increase profitability, it is important for a refinery to maximize the yields of finished products and to minimize the costs of crude oil and other feedstocks and operating expenses, and to do so without compromising safety and environmental performance. According to the U.S. Energy Information Administration (the “EIA”), as of January 1, 2012, there were 134 oil refineries operating in the United States. High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. Domestic operating refining capacity increased approximately 4% between January 1982 and January 2012, from 16.1 million barrels per day (“bpd”) to 16.7 million bpd, according to the EIA. Much of this increase in capacity is the result of efficiency measures and moderate expansions at various refineries, known as “capacity creep,” but some significant expansions at existing refineries have occurred as well. During this same time period, more than 120 smaller and less efficient refineries that had limited access to a wide variety of crude oils or were unable to profitably process feedstock into a marketable product mix were closed.

Crude oil supply and demand dynamics can vary by region, creating differentiated margin opportunities depending on a given refinery’s location. Our Nixon Facility is located in the Gulf Coast region of the United States, which is represented in part as PADD III by the EIA.

According to the EIA, total demand for refined products in PADD III represented approximately 20.9% of total U.S. refined products demand from 2007 to 2011. Total refinery capacity for PADD III in May 2012 was 8.7 million bpd with total throughput at 8.2 million bpd, representing a refinery utilization rate of approximately 93.8%. Refinery capacity exceeds refined product demand with finished petroleum products consumed in the region totaling 3.5 million bpd, causing refiners in PADD III to supply all other PADDs. Despite this high level of refining capacity relative to the refined product demand, refiners who can access advantageous crude supplies are still able to achieve high margins.


The following map illustrates U.S. oil refinery capacity as of July 2012:
 

Source: EIA, Refinery Capacity Report, 2012.

Business Strategies

Our management team is dedicated to improving our operations by executing the following strategies:

  
Concentrate on Stable Cash Flows - We intend to continue to focus on operating assets and businesses that generate stable cash flows;

  
Maintain Efficient Refinery Operations and Promote Operational Excellence and Reliability - For the year ended December 31, 2012, our Nixon Facility maintained a utilization rate of approximately 65%. We intend to continue to operate our refinery as reliably and efficiently as possible to optimize utilization and further improve our operations by maintaining our costs at competitive levels. We will continue to devote significant time and resources toward improving the reliability of our operations. We will also seek to improve operating performance through commitment to our preventive maintenance program and to employee training and development programs;

  
Enhance Profitability of Our Existing Assets and Invest in Organic Growth - We are focused on the profitable enhancement of our existing operations by:

-  
continuing to make investments to enhance the operating flexibility of the Nixon Facility;
-  
pursuing organic growth projects at the Nixon Facility to increase utilization and  improve the efficiency of our operations; and
-  
optimizing current operations through energy savings initiatives, product quality enhancements and product yield improvements.
 
 
  
Pursue Strategic and Complementary Acquisitions - We will seek to acquire assets and product lines where we can enhance operations and improve profitability in geographic or product areas that would diversify our operating footprint. In addition, we may also pursue accretive acquisitions within our refining operations, both in our existing areas of operations as well as in new geographic regions that would also diversify our operating footprint. In evaluating acquisitions within the refining industry, we will consider, among other factors, sustainable financial performance of the targeted assets through the refining cycle, access to advantageous sources of crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure, and potential operating synergies.
 
Recent Developments
 
In February 2013, we announced that our Board of Directors (the “Board”) has decided to explore strategic alternatives intended to enhance stockholder value, specifically our conversion from a corporation into a master limited partnership. A special committee of independent directors was established to explore the feasibility of our conversion from a corporation into a master limited partnership and has engaged Stout Risius Ross to act as its financial advisor. The special committee, with the assistance of its financial advisors, will consider and review the terms and conditions of any conversion and make a recommendation to the Board. There can be no assurance that the exploration of strategic alternatives will result in our conversion from a corporation into a master limited partnership.
 
Ongoing Acquisition and Disposition Activities

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

The closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts, including those described below, 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.

Lazarus Texas Refinery I, LLC (“LTRI”) Option.  In June 2012, we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LTRI, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LTRI’s assets include a refinery, located on a 104 acre site in Ingleside, San Patricio County, Texas (the “Ingleside Refinery”).  The Ingleside Refinery consists of crude oil and condensate processing equipment, pipeline connections, trucking terminals and related storage, storage tanks, a barge dock and receiving facility, pipelines, equipment, related loading and unloading facilities and utilities.

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

Lazarus Energy Development, LLC (“LED”) Option.  In February 2012 we purchased an exclusive option, which expires on September 4, 2013, from LEH to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH.  LED owns approximately 46 acres of real property, which is located adjacent to the Nixon Facility in Nixon, Wilson County, Texas.  We paid LEH a fully refundable sum of $183,421 in cash as consideration to purchase this option.
Disposition of Working Interest in North Sumatra Basin. On November 6, 2012, we announced that Blue Dolphin Exploration Company (“BDEX”), a wholly-owned subsidiary, entered into a Sale and Purchase Agreement (the “Indonesia SPA”) with Blue Sky Langsa Limited (“Blue Sky”) for the disposal of its 7% undivided working interest in the North Sumatra Basin – Langsa Field offshore Indonesia (“Indonesia”) for approximately $800,000. As a result, our operations related to Indonesia ceased effective November 6, 2012 and the disposal was completed on February 28, 2013. We have reflected the results of Indonesia as discontinued operations in the financial statements. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” for additional disclosures regarding Indonesia and discontinued operations.

Management of Blue Dolphin’s Assets. In connection with our acquisition of LE, we entered into a Management Agreement with LEH (the “Management Agreement”) pursuant to which LEH manages and operates the Nixon Facility and Blue Dolphin’s other operations (collectively, the “Services”). Pursuant to the Management Agreement, LEH receives as compensation for Services, the right to receive (i) weekly payments not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Management Agreement, up to a maximum quantity of 10,000 barrels per day determined on a monthly basis, and (iv) $2.50 for each barrel in excess of 10,000 bpd processed at the Nixon Facility during the term of the Management Agreement, determined on a monthly basis. We also agreed to reimburse LEH at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Management Agreement is to be paid to LEH within 30 days of the end of each calendar month.

The Management Agreement expires upon the earliest to occur of (a) the date of the termination of the Joint Marketing Agreement between LE and GELTex Marketing, LLC (“GEL”) dated August 12, 2011(the “Joint Marketing Agreement”), which has an initial term of three years and year-to-year renewals at the option of either party thereafter, (b) August 12, 2014, or (c) upon written notice of either party to the Management Agreement of a material breach of the Management Agreement by the other party. If the Management Agreement is renewed after the expiration of its initial term, then it will thereafter be reviewed on an annual basis by the Board and it may be terminated if the Board determines that the Management Agreement is no longer in our best interests.


Our Refinery
 
The Nixon Facility is a crude oil and condensate processing facility that has a current operating capacity of approximately 15,000 bpd. The Nixon Facility had no operations during 2011. The Nixon Facility can produce products such as Non-Road Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), kerosene, jet fuel and intermediate products such as liquefied petroleum gas, naphtha and atmospheric gas oil. Currently, the Nixon Facility is operated as a “topping unit,” processing light crude oil and condensate from south Texas, including the Eagle Ford Shale formation, into NRLM for sale into nearby markets and naphtha and atmospheric gas oil for sale to nearby refineries for further processing.

The Nixon Facility is located on a 56-acre site in Nixon, Wilson County, Texas, and consists of a distillation unit, naphtha stabilizer, recovery facilities with approximately 120,000 barrels of crude oil storage capacity and 148,000 barrels of refined product storage capacity, as well as related loading and unloading facilities and utilities. Currently we purchase crude oil and condensate under a supply agreement with GEL, an affiliate of Genesis Energy, LLC (“Genesis”). We currently receive our feedstock by truck, however, the Nixon Facility also has the ability to receive crude oil and condensate via pipeline. Our refined products are currently sold and delivered by truck and barge. The following table sets forth historical information about production at our Nixon Facility since it was returned to service in February 2012:

   
Year Ended December 31, 2012
Nixon Facility
   
Crude oil throughput capacity
 
15,000 bpd
Total feedstock runs(1)
 
3,175,283 bbls
Total refinery production
 
3,116,649 bbls

(1)  
Total feedstock runs represents the barrels of crude oil and other feedstocks processed.

Pipeline Operations

Our pipeline operations, which represented less than 1% of total revenue for the twelve months ended December 31, 2012, involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore in the vicinity of our pipelines in the U.S. Gulf of Mexico. We charge producers and shippers a fee based on anticipated throughput volumes. All of our pipeline assets are held by and the business conducted by Blue Dolphin Pipe Line Company. Unless otherwise stated herein, all natural gas liquid volumes transported are attributable to production from third-party producers/shippers.

Pipeline Assets. The following provides a summary of our pipeline assets at December 31, 2012:
 
Pipeline Segment
 
Market
 
Ownership
   
Miles of Pipeline
   
Capacity (MMcf/d)
 
                       
BDPS
 
U.S. Gulf of Mexico
    83.3 %     38       180  
GA 350
 
U.S. Gulf of Mexico
    83.3 %     13       65  
Omega
 
U.S. Gulf of Mexico
    83.3 %     18       110  

  
Blue Dolphin Pipeline System (“BDPS”) – The BDPS spans approximately 38 miles and runs from a junction platform in Galveston Area Block 288 offshore (“GA-288”) to our onshore facilities in Freeport, Texas (the “Freeport Plant”) and then to the Dow Chemical Plant Complex also in Freeport, Texas. For oil production, we handle offshore transportation. Onshore transportation, facilities services (such as storage) and sale are handled by a third-party. For natural gas production, we handle offshore and onshore transportation, facilities services (such as separation and dehydration) and sale of the natural gas to Dow Chemical Company. The BDPS has an aggregate capacity of approximately 180 MMcf of gas and 7,000 Bbls of crude oil and condensate per day. The average throughput on the BDPS for the twelve months ended December 31, 2012 was 3.0 MMcf of gas per day, which represented 1.3% of throughput capacity, compared to average throughput of 4.4 MMcf of gas per day, which represented 2.0% of throughput capacity for the twelve months ended December 31, 2011.
 
The BDPS includes: (i) approximately 193 acres of land in Brazoria County, Texas where the Blue Dolphin Pipeline comes ashore and where the Freeport Plant, pipeline easements and rights-of-way are located, (ii) the offshore junction platform in GA-288 and (iii) the 20-inch Blue Dolphin Pipeline. The BDPS gathers and transports oil and natural gas from various offshore fields in the Galveston Area of the U.S. Gulf of Mexico to our Freeport Plant.
 
 
  
Galveston Area Block 350 Pipeline (the “GA 350”) – The GA 350 is an 8-inch, 13 mile offshore pipeline extending from Galveston Area Block 350 to a point of terminus with a third-party transmission pipeline in Galveston Area Block 391, which is located approximately 14 miles south of the BDPS. For oil and natural gas production, we handle offshore transportation through the GA-350 to the third-party transmission pipeline. Current system capacity on the GA 350 is 65 MMcf of gas per day. The average throughput on the GA 350 for the twelve months ended December 31, 2012 was 16.5 MMcf of gas per day, which represented 25.4% of throughput capacity, compared to average throughput of 13.6 MMcf of gas per day, which represented 20.9% of throughput capacity for the twelve months ended December 31, 2011.

  
Omega Pipeline (the “Omega”) – The Omega 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 is currently inactive. Reactivation of the Omega is dependent upon future drilling activity in the vicinity and successfully attracting producer/shippers to the system.

Exploration and Production

Our oil and gas exploration and production activities, which include leasehold interests in properties located in the U.S. Gulf of Mexico, were uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012. Our U.S. Gulf of Mexico oil and gas properties were fully impaired for the twelve months ended December 31, 2011.  See “Part I, Item 1. Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basin” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

 
Remainder of Page Intentionally Left Blank
 

Exploration and Production Assets. The following provides a summary of our oil and gas properties at December 31, 2012:
 
Field
 
Operator
 
Interest
         
U.S. Gulf of Mexico:
       
High Island Block 115
 
Rooster Petroleum, LLC
 
2.5% WI, 2.008% NRI
Galveston Area Block 321
 
Black Elk Energy Offshore Operations LLC
 
0.5% ORRI
High Island Block 37
 
EPL Oil & Gas, Inc.
 
2.88% WI, 2.246% NRI
 
High Island Block 115 – High Island Block 115 is located approximately 30 miles southeast of Bolivar Peninsula in an average water depth of approximately 38 feet. The B-1 ST2 Well was shut-in in early November 2012 to undergo wellhead repairs. The wellhead was not holding adequate pressure to meet federal regulatory standards. Work on the wellhead is estimated to occur in the first quarter of 2013.

Galveston Area Block 321 – Galveston Area Block 321 is located approximately 32 miles southeast of Galveston in an average water depth of approximately 66 feet. The A-4 Well is currently shut-in. The well had no oil production in 2012 and last produced gas in September 2012. In December 2012, the operator did a recompletion of the well; the recompletion was not successful.  The operator has indicated plans to relinquish the lease in the first quarter of 2013.

High Island Block 37 High Island Block 37 is located approximately 15 miles south of Sabine Pass in an average water depth of approximately 36 feet. The block contains no active wells. The operator’s lease in the block expired in February 2012. At lease expiration, the operator indicated plans to plug and abandon the B-1 Well, remove the B-structure and temporary abandon the A-2 Well within one year of the lease expiration date. In October 2012, the operator assigned its interest in the block to another operator. The new operator completed temporary abandonment of the A-2 Well in January 2013. There has been no further indication of plans related to the B-1 Well.

Productive Wells and Acreage. The following table sets forth our ownership interest at December 31, 2012 in productive oil and natural wells in the areas indicated. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells reflect the total number of producing wells in which we have an interest, and net wells are determined by multiplying gross wells by our average working or royalty interest. Productive wells consist of producing wells and wells capable of production.
 
   
Oil
   
Natural Gas
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
U.S. Gulf of Mexico
                                   
Working Interest
    -       -       1.0       0.1       1.0       0.1  
Overriding Royalty Interest
    -       -       1.0       -       1.0       -  
      -       -       2.0       0.1       2.0       0.1  


The following table sets forth the approximate developed and undeveloped acreage that we held as leasehold interest at December 31, 2012. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves.
 
   
Developed
   
Undeveloped
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
U.S. Gulf of Mexico
    17,280       264       -       -       17,280       264  
      17,280       264       -       -       17,280       264  
 
Production, Price and Cost Data. The following table presents information regarding production volumes and revenue, average sales prices and costs (after deduction of royalties and interests of others) with respect to crude oil, condensate and natural gas attributable to our interests in the Gulf of Mexico for each of the periods indicated.
 
   
Years Ended December 31,
 
   
2012
   
2011
 
Crude Oil and Condensate:
           
Production (Bbls)
    11       -  
Revenue
  $ 1,087       -  
Average production per day (Bbls) (*)
    0.3       -  
Average sales price per Bbl
  $ 98.82       -  
Natural Gas:
               
Production (Mcf)
    11,594       -  
Revenue
  $ 27,272       -  
Average production per day (Mcf) (*)
    31.8       -  
Average sales price per Mcf
  $ 2.35       -  
                 
Production Costs (**):
               
Per Mcfe:
  $ -       -  
__________________
 
(*)
Average production is based on a 365 day year.
 
(**)
Production costs, exclusive of work-over costs, are costs incurred to operate and maintain wells and equipment and to pay production taxes.
 
Drilling, Exploration and Development Activity. During the twelve months ended 2012, Black Elk Energy Offshore Operations LLC, operator of the Galveston Area Block 321 A-4 Well, did a recompletion of the well. The recompletion was not successful. During 2011, there was no drilling, exploration or development activity associated with our oil and gas leasehold interests.

Other Assets

We own a non-hazardous Class I salt water disposal well located near the town of Mermentau, Jefferson Davis Parish, Louisiana. The well is currently inactive.


Raw Material Supply

The single input for our refinery is crude oil and condensate. In August 2011, we and GEL entered into the Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”).

The Crude Supply Agreement provides that we will exclusively obtain all of the crude oil for our Nixon Facility through GEL, other than the crude oil purchased from any other supplier with the prior consent of GEL. All crude oil supplied pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. 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.

The Crude Supply Agreement has an initial term of three years and expires on August 12, 2014, subject to certain termination rights. Following the initial term, the Crude Supply Agreement will automatically renew for successive one-year terms unless either party provides the other with notice of nonrenewal at least 90 days prior to expiration of the initial Term or any renewal term.

Customers

Customers for 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 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 refined petroleum products. For the twelve months ended December 31, 2012, our four largest customers accounted for approximately 84% of our refined petroleum products sales.

Markets and Competition

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

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

Intellectual Property

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


Employees

Pursuant to the Management Agreement, all Blue Dolphin subsidiaries are managed by LEH and all personnel work directly for LEH. LEH is reimbursed for providing personnel services under the Management Agreement.

Governmental Regulation

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

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

We cannot predict the extent to which additional environmental, health, and safety laws will be enacted in the future, or how existing or future laws will be interpreted with respect to our operations. Many environmental, health, and safety laws and regulations are becoming increasingly stringent. The cost of compliance with and governmental enforcement of environmental, health, and safety laws may increase in the future. We may be required to make significant capital expenditures or incur increased operating costs to achieve compliance with applicable environmental, health, and safety laws.

The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 (the “Energy Acts of 2005 and 2007”). Pursuant to the Energy Acts of 2005 and 2007, the Environmental Protection Agency (the “EPA”) issued Renewable Fuels Standards (“RFS”) that mandate the blending of renewable fuels into refined petroleum fuel products. The Nixon Facility is currently not subject to this requirement. However, on an annual basis, the EPA establishes new volume requirements and associated percentage standards that subject refineries to RFS. The volume requirements and associated percentage standards increase through 2022, when all facilities will be subject to the requirements.

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

 
The CAA also authorizes the EPA to require modifications in the formulation of refined fuel products. In 2007, the EPA issued a second Mobile Source Air Toxics standard (the “MSAT II”) that required significant reductions in the sulfur content in gasoline and diesel fuel. These standards required most refineries to reduce the sulfur content in diesel to 15 ppm and gasoline to 30 ppm. Low sulfur (500 ppm) and Ultra Low Sulfur Diesel (ULSD) fuel is expected to be phased in for NRLM engines in 2014. When implemented for NLRM, the MSAT II requirements may require us to undergo additional permitting and/or incur capital expenditures to meet the new requirements. We do not currently manufacture gasoline.

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

In addition to new greenhouse gas regulations, Congress has from time to time considered legislation to reduce greenhouse gas emissions. Almost one-half of the states have already taken measures to reduce greenhouse gas emissions through the establishment of greenhouse gas emission inventories and regional cap-and-trade programs. The adoption of future legislation limiting greenhouse gas emissions could cause us to incur additional compliance costs and may affect the demand for our products.

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

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

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

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

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

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

 
Environmental

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

Available Information

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

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

Glossary of Industry Terms

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

Atmospheric Gas Oil. The heaviest product boiled by a crude distillation unit operating at atmospheric pressure. This fraction ordinarily sells as distillate fuel oil, either in pure form or blended with cracked stocks. In-blends atmospheric gas oil, often abbreviated AGO, usually serves as the premium quality component used to lift lesser streams to the standards of saleable furnace oil or diesel engine fuel. Certain ethylene plants, called heavy oil crackers, can take AGO as feedstock.

Back-in After Payout Interest. A contractual right of a non-participating partner to participate in a well or wells after the wells have produced enough for the participating partners to recover their capital costs of drilling, completing and operating the wells.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

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. Barrel per day.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Condensate. Hydrocarbons that are in a gaseous state under reservoir conditions and become liquid when temperature or pressure is reduced; a mixture of pentanes and higher hydrocarbons.

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

Crude Oil. A mixture of thousands of chemicals and compounds, primarily hydrocarbons. Crude oil must be broken down into its various components by distillation before these chemicals and compounds can be used as fuels or converted to more valuable products. There are primarily five types of crude – West Texas Intermediate (“WTI”), Light Crude, Sweet Crude, Sour Crude and Brent Crude. See definitions of WTI, Light Crude, Sweet Crude and Sour Crude.

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

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

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

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

Development Well. A well drilled within the proved area of a gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Distillate. The liquid that has been condensed from vapor during distillation; normally a purified form or a fraction of an original liquid.

Distillation. The first step in the refining process. During distillation, crude oil is heated in the base of a distillation tower. As the temperature increases, the crude's various compounds vaporize in succession at their various boiling points and then rise to prescribed levels within the tower according to their densities. They then condense in distillation trays and are drawn off individually for further refining. Distillation is also used at other points in the refining process to remove impurities.

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

Exploratory Well. A well drilled to find and produce gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of gas or oil in another reservoir or to extend a known reservoir.

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

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

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

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

Heat Exchanger. See definition for Exchanger.

Jet Fuel. A type of aviation fuel. Kerosene-type jet fuel (including Jet A and Jet A-1) has a carbon number distribution between about 8 and 16 carbon atoms per molecule; wide-cut or naphtha-type jet fuel (including Jet B) has between about 5 and 15 carbon atoms per molecule.

Kerosene. A thin, clear liquid formed from hydrocarbons. Obtained from the fractional distillation of petroleum between 150 °C and 275 °C, resulting in a mixture of carbon chains that typically contain between 6 and 16 carbon atoms per molecule.

Leasehold Interest. The interest of a lessee under an oil and gas lease.

Light Crude. Crude oil with a low wax content.

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

Mbbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one barrel of oil, condensate or gas liquids.

MMbtu. One million British Thermal Units.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Naphtha. A broad term covering among the lightest and most volatile fractions of the liquid hydrocarbons in petroleum. Naphtha is a colorless to reddish-brown volatile aromatic liquid, very similar to gasoline.

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

Non-operating Working Interest. A working interest, or a fraction of a working interest, in a lease where the owner is not the operator of the lease.

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

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

Petroleum. A naturally occurring flammable liquid consisting of a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds. The name petroleum covers both the naturally occurring unprocessed crude oils and petroleum products that are made up of refined crude oil.

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.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of oil, gas or both.

Proved Developed Reserves.  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved developed reserves are further categorized into two sub-categories -- proved developed producing reserves and proved developed non-producing reserves.

Proved Developed Producing. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate.

Proved Developed Non-producing. Reserves sub-categorized as non-producing, which include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from: (i) completion intervals which are open at the time of the estimate but which have not started producing, (ii) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (iii) wells not capable of producing for mechanical reasons.

Proved Reserves. The estimated quantities of oil, gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves are further categorized into two sub-categories – proved developed and proved undeveloped depending on their development and production status.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells or from existing wells where a relatively significant expenditure is required for recompletion.

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 comprises the integrated application of a set of engineering techniques and procedures to check, inspect and test every operational component of the project, from individual functions, such as instruments and equipment, up to complex amalgamations such as modules, subsystems and systems.

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

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

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

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

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

Sweet Crude. Crude oil containing sulfur content of less than 0.5%. Commonly used for processing into gasoline.

Sulfur. Present at various levels of concentration in many hydrocarbon deposits, such as petroleum, coal or natural gas. Also produced as a byproduct of removing sulfur-containing contaminants from natural gas and petroleum. Some of the most commonly used hydrocarbon deposits are categorized according to their sulfur content, with lower sulfur fuels usually selling at a higher, premium price and higher sulfur fuels selling at a lower, or discounted, price.

Topping Unit (Atmospheric Distillation). Conducts the initial transformation of crude oil at a refinery. The topping unit heats crude oil at atmospheric pressure to accomplish the first rough distillation cut. Lighter products produced in this process can be further refined in a catalytic cracking unit or reforming unit. Heavier products, which cannot be vaporized and separated in this process, can be further distilled in a vacuum distillation unit or coker.

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

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

Undivided Interest. A form of ownership interest in which more than one person concurrently owns an interest in the same oil and gas lease or pipeline.

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

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


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

Risks Related to our Business

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

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

 
In May 2012, we implemented an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.
 
Our operations are highly dependent on our relationship with Genesis, and, if we are unable to successfully maintain this relationship, our operations, liquidity and financial condition will be harmed.
 
We are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil, transportation of crude oil, provision of accounting and other services, joint marketing of our refined petroleum products and funding of renovations, expansion and other capital expenditures relating to the Nixon Facility. Further, we have an understanding with Genesis relating to an inventory risk management system, which is intended to reduce the commodity price risk of our finished products inventory and generate a more consistent gross margin for each barrel of refined product. These agreements and understandings require us to have a close working relationship with Genesis in order for us to be successful in fully executing our business strategy. If we are unable to maintain this relationship or our relationship is not on good terms, we believe that it could have a material adverse effect on our operations, liquidity and financial condition.
 
We are currently in default under certain of our long-term debt and are operating under forbearance agreements. Our failure to comply with provisions contained in the forbearance agreements, including as a result of events beyond our control, could materially and adversely affect our operating results and our financial condition.
 
We cannot assure that our assets or cash flow would be sufficient to fully repay borrowings under our outstanding notes payable, either upon maturity or if accelerated, or that we would be able to refinance or restructure the payments on the notes payable. If we fail to comply with provisions contained in the forbearance agreements, then the senior lender may exercise any rights and remedies available under the loan agreement and applicable law including, without limitation, foreclosing on our assets. Any such action by our senior secured lender would have a material adverse effect on our financial condition and ability to continue as a going concern.
 
We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.
 
Historically, we have used a portion of our cash reserves to fund our working capital requirements that were not funded from our operations.  Most recently, we have relied on advances under the Construction Funding Agreement and revenue from operations, including sales of refined products and rental of storage tanks, to fund our working capital requirements.  Currently we expect that these resources will be sufficient to satisfy our anticipated working capital requirements over the next 12 – 18 months.  If we cannot generate sufficient cash flows from operations, continue to make advances under the Construction and Funding Agreement or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to repayment of the Refinery Loan.  Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades at the Nixon Facility.  In addition, from time to time, we expect to utilize significant capital to upgrade equipment, improve facilities and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.
Our primary source of crude oil supply experiences significant price swings, which impacts our crude oil acquisition cost.

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

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

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

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

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

  
changes in global and local economic conditions;
  
domestic and foreign demand for fuel products, especially in the United States, China and India;
  
worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;
  
the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported into the United States;
  
availability of and access to transportation infrastructure;
  
utilization rates of U.S. refineries;
  
the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;
  
development and marketing of alternative and competing fuels;
  
commodities speculation;
  
natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;
  
federal and state government regulations and taxes; and
  
local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.
 
Loss of market share with or by a key customer, or consolidation among our customer base, could harm our operating results.
 
For the twelve months ended December 31, 2012, a large percentage of our revenue, 84%, came from sales to four 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 likely 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.
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 specialty products prices and the prices for crude oil. The cost to acquire crude oil and the price at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control.
 
The prices at which we sell specialty products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our specialty products segment margins will fall unless we are able to pass along these price increases to our wholesale customers. Increases in selling prices for specialty products typically lag the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period of time.

The sale of refined petroleum products to the wholesale market is an important part of our business going forward, and if we fail to grow and maintain our market share or gain market acceptance of our refined petroleum products, our operating results could suffer.

Selling refined petroleum products to the wholesale market is an important part of our business, and as our refined petroleum products revenue increases as a portion of our overall revenue, our success in the wholesale market becomes increasingly important to our operating results. Our success in the wholesale market depends in large part on our ability to grow and maintain our image and reputation as an independent 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-party operators for the transportation of crude oil into and refined petroleum products out of our Nixon Facility, and if these third-party operators become unavailable to us, our ability to process crude oil and sell refined petroleum products to wholesale markets could be materially and adversely affected.

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

Potential downtime for maintenance at the Nixon Facility could reduce our revenue and cash available for payments of our obligations.

Although currently operating at anticipated levels, the Nixon Facility is still in a recommissioning phase and may require additional unscheduled downtime for unanticipated maintenance or repairs. Any scheduled or unscheduled maintenance reduces our revenues and increases our operating expenses during the period of time that our processing unit is not operating and could reduce our ability to meet our payment obligations.

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

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

LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock. Through its ownership of such a large amount of Common Stock, LEH has significant influence over matters such as the election of our 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 our stockholders. LEH and its other affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities. We believe that the transactions and agreements that we have entered into with LEH and its affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third parties. However, these relationships could create, or appear to create, potential conflicts of interest when our Board is faced with decisions that could have different implications for us and LEH or its affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter into new relationships in the future, which may have a material adverse effect on our ability to do business.

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

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

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

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in the PADD III region of the United States as defined by the EIA, as well as with domestic refiners in other PADD regions and foreign refiners that import products into the United States. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain all of our feedstocks from a single source. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.  If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.
 
We may not be able to successfully execute our strategy of growth within the refining industry through acquisitions.

A component of our growth strategy is to selectively consider accretive acquisitions within the refining industry based on sustainable performance of the targeted assets through the refining cycle, access to advantageous crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure and potential operating synergies. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:

  
diversion of management time and attention from our existing business;
  
challenges in managing the increased scope, geographic diversity and complexity of operations;
  
difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;
  
liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;
  
greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results;
  
difficulties in achieving anticipated operational improvements; and
  
incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

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

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

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

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

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

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

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

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 or incur increased operating costs or change operations to achieve compliance with applicable standards.

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

 
In 2014, new environmental regulations become effective that reduce the allowable sulfur content for commercially sold diesel in the United States. Unless the Nixon Facility undergoes significant capital upgrades, we may be limited to selling “off specification” diesel at lower prices.
 
New environmental regulations will become effective in 2014 that reduce the sulfur content that is permitted to be contained in diesel sold commercially in the United States. In order to meet the higher content standards, the Nixon Facility may require capital upgrades in excess of approximately $50 million. In order to complete the required capital upgrades, we will have to finance such capital expenditures primarily through the issuance of debt and/or equity, which would result in dilution to existing stockholders and/or subject us to higher debt levels. There can be no assurance that we can obtain such financing at rates or at terms acceptable to us, if at all.

Regulation of greenhouse gas emissions could increase our operational costs and reduce demand for our products.
 
Continued political attention to issues concerning climate change, the role of human activity in it, and potential mitigation through regulation could have a material impact on our operations and financial results.
 
International agreements and national or regional legislation and regulatory measures to limit greenhouse emissions are currently in various stages of discussion or implementation. These and other greenhouse gas emissions-related laws, policies and regulations may result in substantial capital, compliance, operating and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, our activities in the particular jurisdiction and market conditions. Greenhouse gas emissions that could be regulated include those arising from the conversion of crude oil into refined petroleum products, the transportation of crude oil and natural gas, and the exploration and production of crude oil and natural gas. Some matters related to these activities, such as actions taken by our competitors in response to such laws and regulations, are beyond our control.

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

None.
 

We lease office space in Houston, Texas, which serves as our company headquarters. LEH operates our owned plant facilities in Nixon, Wilson County, Texas and Freeport, Brazoria County, Texas. LEH is reimbursed for the management and operation of these facilities under the Management Agreement.

See “Part I, Item 1. Business – Exploration and Production” of this report for information regarding our oil and gas leasehold interests. Such information is incorporated herein by reference.
 


Pursuant to a Settlement Agreement and Mutual Release by and among Blue Dolphin, LEH and Lazarus Louisiana Refinery II, LLC (“LLRII”) effective February 15, 2012, the parties agreed to settle and compromise all disputes between them in connection with closing of the LE Acquisition. LEH agreed to file a non-suit with prejudice of all pending claims against Blue Dolphin under Cause No. 210-32561, styled Blue Dolphin Energy Company v. Lazarus Energy Holdings, L.L.C. and Lazarus Louisiana Refinery II, L.L.C., in the 129th District Court of Harris County, Texas (the “Lawsuit”). Blue Dolphin agreed that it will not execute or attempt to execute on an order that was signed on May 16, 2011 in the Lawsuit severing LEH’s counterclaims into Cause No. 2010-32561-A, which resulted in a Partial Summary Judgment becoming a final judgment in Blue Dolphin’s favor. Pursuant to an Order of Nonsuit and Dismissal with Prejudice, a presiding judge ordered, adjudged and decreed that counter-plaintiff LEH’s claims and causes of action in the Lawsuit were dismissed on July 6, 2012.

From time to time we are subject to various lawsuits, claims, liens and administrative proceedings that arise out of the normal course of business. During the twelve months ended December 31, 2012, a vendor placed a mechanic’s lien on the Nixon Facility as protection during construction activities. Management does not believe that the lien will have a material adverse effect on our results of operations.


Not applicable.


 

 
Remainder of Page Intentionally Left Blank
 
 
 
 



Market Information

Our Common Stock is quoted on the OTCQX U.S. Premier tier 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  
             
2012            
 December 31   $ 6.50     $ 3.85  
 September 30   $ 7.95     $ 6.01  
  June 30   $ 9.22     $ 6.18  
 March 31   $ 11.60     $ 4.28  
                 
2011(1)                
 December 31   $ 2.88     $ 1.70  
 September 30   $ 3.64     $ 0.99  
 June 30   $ 4.90     $ 1.33  
 March 31   $ 3.71     $ 2.24  
______________                
(1)  Between June 13, 2011 and September 1, 2011, our Common Stock traded on the OTCQB.

Simultaneous with the delisting of our Common Stock from the Nasdaq Capital Market on February 28, 2012, our Common Stock began trading on the OTCQX U.S. Premier tier of the OTC Markets under the ticker symbol “BDCO."

Holders

As of March 29, 2013, we had 287 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. We are a holding company that conducts substantially all of our operations through our subsidiaries. As a result, our ability to pay dividends on the Common Stock will also be dependent upon the cash flow of our subsidiaries.



Not applicable.
 

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

Executive Summary

In February 2012, we acquired LE, which owned the Nixon Facility. Historically, we were engaged in two lines of business: (i) pipeline transportation services to producers/shippers and (ii) oil and gas exploration and production. As a result of the acquisition of LE our primary business is the refining of crude oil into marketable finished and refined products such as Non-Road, Locomotive and Marine Diesel Fuel (“NRLM” or “off-road diesel”), naphtha and atmospheric gas oil. As part of our refining business, we also conduct petroleum storage and terminaling operations under third party lease agreements at the Nixon Facility. We also continue to own and operate pipeline assets and have leasehold interests in oil and gas properties.

Under applicable accounting rules LE, although a subsidiary of Blue Dolphin, was treated as the accounting parent and Blue Dolphin was treated as the accounting subsidiary. Accordingly, the financial statements after the date of the acquisition of LE are presented as a continuation of LE. The Nixon Facility, LE's primary asset, was returned to service in February 2012 and had no operations during 2011.

The acquisition of LE represents a fundamental change in our business. Increases in our revenue, operating expenses and other related costs are primarily attributable to our refining operations.


Operational Highlights
 
Operational highlights for our core business segment, refinery operations, follows:

Current Year

 
Refinery Operations
Operated a total of 326 days; average throughput was approximately 9,700 bpd, or 65% of operating capacity (the Nixon Facility began operations in February 2012).

 
Petroleum Storage and Terminaling
85,000 bbls of tankage under lease agreement.

Prior Year

 
Refinery Operations
The Nixon Facility had no operations during the prior year.

 
Petroleum Storage and Terminaling
20,000 bbls of tankage under lease agreement.
 
Major Influences on Results of Operations

Earnings and cash flow from our refining operations are primarily affected by the difference between refined product prices and the prices for crude oil and other feedstocks. The cost to acquire crude oil and other feedstocks and the price of the refined petroleum products we ultimately sell depend on numerous factors beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined petroleum products, which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While our sales and operating revenues fluctuate significantly with movements in crude oil and refined product prices, it is the spread between crude oil and refined product prices, and not necessarily fluctuations in those prices, which affect our earnings.

In order to measure our operating performance, we compare our per barrel refinery operating margins to certain industry benchmarks. We calculate the per barrel operating margin for the Nixon Facility by dividing the refinery’s gross margin by its throughput volumes. Gross margin is the difference between net sales and cost of sales (excluding any substantial unrealized hedge positions and certain inventory adjustments).
 
The Nixon Facility has the capability to process substantial volumes of low-sulfur crude oils (sweet crude) to produce a high percentage of light, high-value refined petroleum products. Sweet crude derived from the surrounding Eagle Ford Shale production currently comprises 100% of the Nixon Facility’s crude oil input.
 
 
Safety, reliability and the environmental performance of the Nixon Facility is critical to our financial performance. The financial impact of a turnaround or major maintenance project is mitigated through a diligent planning process that considers expectations for product availability, margin environment and the availability of resources to perform the required maintenance.

The nature of our business requires us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined petroleum products are essentially commodities, and we have no control over the changing market value of these inventories. In May 2012 we implemented an inventory risk management policy in which derivative instruments may be used as economic hedges to reduce our crude oil and refined petroleum products inventory commodity price risk.

Relationship with Genesis

We are dependent on our relationship with Genesis and its affiliates. Our relationship with Genesis is governed primarily by three agreements:
 
the Crude Oil Supply and Throughput Services Agreement by and between GEL and LE dated August 12, 2011 (the “Crude Supply Agreement”);
 
the Construction and Funding Contract by and between LE and Milam Services, Inc., an affiliate of Genesis (“Milam”), dated August 12, 2011 (the “Construction and Funding Agreement”); and
 
the Joint Marketing Agreement by and between GEL and LE dated August 12, 2011 (as subsequently amended, the “Joint Marketing Agreement”).
 
Below is a discussion of the material terms and conditions of each of our agreements with Genesis.
 
Crude Supply Agreement -- Pursuant to the Crude Supply Agreement, GEL is the exclusive supplier of crude oil to the Nixon Facility. We are not permitted to buy crude oil from any other source without GEL’s express written consent. GEL supplies crude oil to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described below. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement has an initial term of three years, expiring on August 12, 2014. After the expiration of its initial term, the Crude Supply Agreement automatically renews for successive one year terms unless either party notifies the other party of its election to terminate the Crude Supply Agreement within 90 days of the expiration of the then current term.
 
Construction and Funding Agreement -- Pursuant to the Construction and Funding Agreement, LE engaged Milam to provide construction services on a turnkey basis in connection with the construction, installation and refurbishment of certain equipment at the Nixon Facility (the “Project”). Milam has continued to make advances in excess of their obligation, for certain construction and operating costs at the Nixon Facility. All amounts advanced to LE pursuant to the terms of the Construction and Funding Agreement bear interest at a rate of 6% per annum. In March 2012 (the month after initial operation of the Nixon Facility occurred), LE began paying Milam, in accordance with the provisions of the Joint Marketing Agreement, a minimum monthly payment of $150,000 (the “Base Construction Payment”) as repayment of interest and amounts advanced to LE under the Construction and Funding Agreement. If, however, the Gross Profits of LE (as defined below) in any given month (calculated as the revenue from the sale of products from the Nixon Facility minus the cost of crude oil) are insufficient to make this payment, then there is a deficit amount, which shall accrue interest (the “Deficit Amount”). If there is a Deficit Amount, then 100% of the gross profits in subsequent calendar months will be paid to Milam until the Deficit Amount has been satisfied in full and all previous $150,000 monthly payments have been made.
 
The Construction and Funding Agreement places restrictions on LE, which prohibit LE from: incurring any debt (except debt that is subordinated to amounts owed to Milam or GEL); selling, discounting or factoring its accounts receivable or its negotiable instruments outside the ordinary course of business while no default exists; suffering any change of control or merging with or into another entity; and certain other conditions listed therein. As of the date hereof, Milam can terminate the Construction and Funding Agreement for a breach or upon termination of the Refinery Loan Forbearance Agreement. If Milam terminates the Construction and Funding Agreement, then: (i) Milam and LE are required to execute a forbearance agreement, the form of which has been previously agreed to, pursuant to which LE will pay Milam a fee of $150,000 per month in order to maintain the forbearance (such amount shall be credited against the amount owed) for a period of six months (during which time Milam will agree not to foreclose pursuant to the Construction and Funding Agreement and, thus, LE has the right to find financing to pay off such amounts), (ii) Milam shall be entitled to receive payment in full for all obligations owed under the Construction and Funding Agreement, (iii) all liens in favor of Milam will remain in full force and effect until released in accordance with the terms of the Construction and Funding Agreement and (iv) upon repayment of all obligations owed to Milam pursuant to the terms of the forbearance agreement executed by Milam and LE, LE shall have no further obligations to Milam or its affiliates under the Construction and Funding Agreement;
 
 
Joint Marketing Agreement -- The Joint Marketing Agreement sets forth the terms of the agreement between LE and GEL pursuant to which the parties will market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. Pursuant to the Joint Marketing Agreement, GEL is responsible for all product transportation scheduling. LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. However, all payments for the sale of output produced at the Nixon Facility will be made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil pursuant to the Crude Supply Agreement) as follows:
 
(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 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 modification to the Nixon Facility or entering into any contracts with third-parties which would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement has an initial term of three years expiring on August 12, 2014. After the expiration of its initial term, the Joint Marketing Agreement shall be automatically renewed for successive one year terms unless either party notifies the other party of its election to terminate the Joint Marketing Agreement within 90 days of the expiration of the then current term. The Joint Marketing Agreement also provides that it may be terminated prior to the end of its then current term under certain circumstances.
 
Amendments and Clarifications to the Joint Marketing Agreement -- The Joint Marketing Agreement was amended and clarified to allow GEL to provide LE with Operations Payments during months in which LE incurred Deficit Amounts.

(a)
In July and August 2012, we entered into amendments to the Joint Marketing Agreement whereby GEL and Milam agreed that Deficit Amounts would be added to our obligation amount under the Construction and Funding Agreement. In addition, the parties agreed to amend the priority of payments to reflect that, to the extent that there are available funds in a particular month, AFNB shall be paid one-tenth of such funds, provided that we will not participate in available funds until Deficit Amounts added to the Construction and Funding Agreement are paid in full.
 
(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.
 
As of December 31, 2012, total advances under the Construction and Funding Agreement, including Deficit Amounts, were $5,206,175. As of December 31, 2012, pursuant to amendments and clarifications to the Joint Marketing Agreement, the net Deficit Amount added to our obligation amount under the Construction and Funding Agreement was $659,883.

As of December 31, 2012, the principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183. For the twelve months ended December 31, 2012, payments made to AFNB under the Refinery Loan in respect of LE’s ratable share of Gross Profits were approximately $287,091.


Results of Operations

Twelve Months Ended December 31, 2012 (the "Current Year") Compared to Twelve Months Ended December 31, 2011 (the "Prior Year")
 
Summary. For the current year we reported a loss from continuing operations, net of tax, of $13,841,066, or a loss of $1.35 per share, on total revenue from operations of $352,094,714. We reported a loss from discontinued operations, net of tax, of $4,443,566, or a loss of $0.43 per share, for the current year. For the prior year, we reported an income from continuing operations, net of tax, of $183,854, or income of $0.02 per share. We had no discontinued operations in the prior year. Under reverse acquisition accounting, the financial statements subsequent to the date of the LE Acquisition are presented as the continuation of LE. Accordingly, Blue Dolphin’s previously reported income and expenses for the prior year are not reflected and instead are the financial results of LE.

Total Revenue from Operations. Substantially all of our revenue came from refined product sales, which generated revenue of $351,665,234, or 99% of total revenue from operations, in the current year. The Nixon Facility had no revenue from operations in 2011.

Cost of Refined Products Sold. Cost of refined petroleum products sold was $342,035,755 for the current year compared to $0 for the prior year. The Nixon Facility had no costs from operations in 2011.

Refinery Operating Expenses. We recorded Nixon Facility operating expenses of $8,603,155 in the current year, all of which were for services provided to us by LEH to manage and operate the Nixon Facility pursuant to the Management Agreement with LEH. See “Part II, Item 8. Financial Statements and Supplementary Data - Note (15), Accounts Payable, Related Party” and "Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence - Related Party Transactions" of this report for additional disclosures related to the Management Agreement. The Nixon Facility had no expenses from operations in 2011.

Pipeline Operating Expenses. We recorded pipeline operating expenses of $391,169 in the current year compared to $0 in the prior year.

Lease Operating Expenses. Lease operating expenses totaled $57,122 in the current year compared to $0 in the prior year.

General and Administrative Expenses. General and administrative expenses increased from $645,444 in the prior year to $2,076,946 in the current year. The expenses in the current year were primarily related to leased corporate personnel costs, as well as consulting, legal and audit expenses.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization increased from $17,684 in the prior year to $1,622,864 in the current year primarily as a result of the Nixon Facility having operations in the current year compared to having no operations in the prior year.

Abandonment Expense. We recognized $1,184,549 of abandonment expense in the current year related to plugging and abandonment costs associated with our High Island A-7 oil and gas property. The amount expensed reflected the amount incurred in the current year less the amount reserved for the asset retirement obligation liability, which was $141,099.  There was no comparable expense in 2011.

Impairment. Due to the continued weakness in our pipeline transportation and oil and gas exploration production business segments and the uncertainty of the timing and speed of recovery, we recorded an impairment of $9,435,745 in the current year. Management currently has no future plans to expand pipeline operations given current market conditions. Therefore an impairment of the pipeline was deemed necessary for the current year. The impairment charge in the current year consisted of $7,990,025 related to our pipeline fixed assets and $1,445,720 related to goodwill, 100% of which was associated with our pipeline transportation and oil and gas exploration production business segments. We recorded $0 in impairment charges in 2011. See “Intangibles – Goodwill and Other” and “Recently Adopted Accounting Guidance” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information related to goodwill, other intangible assets, impairment of goodwill and impairment of long-lived assets.
 

Other Income. We recognized $534,047 in net tank rental revenue in the current year compared to $874,421 in the prior year.

Discontinued Operations, Net of Tax. In November 2012, BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. In connection with the Indonesia SPA, we adjusted the value of our oil and gas interest in Indonesia to $800,000, which resulted in an impairment charge of $3,858,427 in the current year. We also recorded an allowance for doubtful accounts receivable of $321,732 in the current year associated with non-payment of accounts receivable for our proportionate share of crude oil liftings revenue due from Blue Sky for Indonesia. Operations associated with Indonesia were reclassified as discontinued operations in the current year. See “Part I, Item 1. Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basin” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

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

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




 
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Following is a reconciliation of EBITDA by business segment for the twelve months ended December 31, 2012 (and at December 31, 2012) and the twelve months ended December 31, 2011 (and at December 31, 2011):
 
   
Twelve Months Ended December 31, 2012
 
   
Segment
             
               
Oil and Gas
             
   
Refinery
   
Pipeline
   
Exploration &
   
Corporate &
       
   
Operations
   
Transportation
   
Production
   
Other(1)
   
Total
 
Revenue
  $ 351,665,234     $ 406,812     $ 22,668     $ -     $ 352,094,714  
Operation cost(2)
  $ 350,940,269     $ 8,676,242     $ 2,018,126     $ 2,270,009       363,904,646  
Other non-interest income
  $ 534,047       -       -       -       534,047  
EBITDA
  $ 1,259,012     $ (8,269,430 )   $ (1,995,458 )   $ (2,270,009 )   $ (11,275,885 )
                                         
Depletion, depreciation and amortization
                                    (1,622,864 )
Other income (expense), net
                                    (932,639 )
                                         
Loss from continuing operations, before income taxes
                                  $ (13,831,388 )
                                         
Loss from discontinued operations
                                  $ (4,443,566 )
                                         
Capital expenditures
  $ 2,852,460     $ -     $ -     $ -     $ 2,852,460  
                                         
Identifiable assets(3)
  $ 52,745,767     $ 1,861,055     $ 48,247     $ 1,726,854     $ 56,381,926  
 
   
Twelve Months Ended December 31, 2011
 
   
Segment
             
   
Crude Oil
         
Oil and Gas
             
   
and Condensate
   
Pipeline
   
Exploration &
   
Corporate &
       
   
Processing
   
Transportation
   
Production
   
Other(1)
   
Total
 
Revenue
  $ -     $ -     $ -     $ -     $ -  
Operation cost(2)
    645,444       -       -       -       645,444  
Other non-interest income
    874,421       -       -       -       874,421  
EBITDA
  $ 228,977     $ -     $ -     $ -     $ 228,977  
                                         
Depletion, depreciation and amortization
                                    (17,684 )
Other income (expense), net
                                    (27,439 )
                                         
Income from continuing operations before income taxes
                                  $ 183,854  
                                         
Capital expenditures
  $ 3,507,850     $ -     $ -     $ -     $ 3,507,850  
                                         
Identifiable assets(3)
  $ 38,144,056     $ -     $ -     $ -     $ 38,144,056  
 
(1)
Includes unallocated general and administrative costs associated with corporate maintenance costs (such as director fees and legal expenses).
(2)
General and administrative costs are allocated based on revenue.
(3)
Identifiable assets contain related legal obligations of each segment including cash, accounts receivable and payable and recorded net assets.


Critical Accounting Policies
 
Goodwill. We recognized goodwill in connection with our reverse merger with LE. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance related to intangibles, goodwill and other. We perform an impairment test annually.

Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.
 
In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment,” in connection with the performance of our annual goodwill impairment testing. Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.

The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill.
 
Other Intangible AssetsWe recognized trade name in connection with our reverse merger with LE. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2012.
 

Impairment of Long Lived Assets. Our policy is to assess the realizability of our long-lived assets, including intangible assets, and to evaluate such assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets (or group of assets) may not be recoverable. Impairment is determined to exist if the estimated future undiscounted cash flows are less than the carrying value. Future cash flow projections include assumptions for future pipeline throughput levels, anticipated capital expenditures and the impact of cost reduction measures and the level of working capital needed to support each business. Any difference between the estimated fair value and the carrying value of the asset is recognized as an impairment. For the years ended December 31, 2012 we recognized an impairment of $7,990,025 related to our pipeline fixed assets.

Recently Adopted Accounting Guidance

In July 2012, FASB amended ASC guidance related to intangibles, goodwill and other. This amendment is intended to reduce the cost and complexity of the annual impairment test for indefinite-lived intangible assets other than goodwill by providing entities an option to perform a qualitative assessment to determine whether further impairment testing is necessary. The amendments are effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption is permitted. We adopted this guidance on in 2012. The adoption did not have a material impact on our consolidated financial position, results of operations or cash flows.

Liquidity and Capital Resources

Sources and Uses of Cash. At December 31, 2012, our available cash was $420,896.
 
   
Three Months Ended December 31,
   
Twelve Months Ended December 31,
 
   
2012
   
2011
   
2012
   
2011
 
                         
Cash flow from operations
                       
Adjusted income (loss) from continuing operations
  $ 2,736,327     $ (50,549 )   $ (1,831,753 )   $ 224,869  
Adjusted loss from discontinued operations
    (435,460 )             (435,460 )        
Change in current assets and liabilities
    811,739       (349,995 )     2,334,540       27,414  
                                 
Total cash flow from operations
    3,112,606       (400,544 )     67,327       252,283  
                                 
Cash inflows (outflows)
                               
Proceeds from issuance of debt
    -       2,851,992       4,788,623       3,304,300  
Payments on long-term debt
    (2,563,062 )     (10,688 )     (3,276,748 )     (42,610 )
Cash acquired on acquisition
    115       -       1,674,709       -  
Proceeds from exercise of stock options
    20,000       -       20,000       -  
Capital expenditures
    (284,011 )     (2,440,292 )     (2,852,460 )     (3,507,850 )
Proceeds from notes payable
    -       -       24,548       -  
Payments on note payble
    (4,025 )     -       (26,925 )     (5,034 )
                                 
Total cash inflows (outflows)
    (2,830,983 )     401,012       351,747       (251,194 )
                                 
Total change in cash flows
  $ 281,623     $ 468     $ 419,074     $ 1,089  


Our sources of liquidity are advances for funding under the Construction and Funding Agreement, revenue we receive under the Joint Marketing Agreement, tank rental income and cash on hand. We purchase our crude oil for the Nixon Facility through an exclusive supply agreement with GEL. Under this agreement, the purchases of the crude oil are completed by GEL. We believe that the aforementioned liquidity sources will be sufficient to satisfy anticipated cash requirements associated with our business during the next 12 to 18 months. Our ability to generate cash to fund our operations depends 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.

For the current year, we experienced positive cash flow from operations of $67,327.  For the three months ended December 31, 2012, we experienced positive cash flow from operations of $3,112,606. This represents an increase compared to negative cash flow from operations of $28,017 for the third quarter of 2012, negative cash flow from operations of $1,438,903 for the second quarter of 2012 and negative cash flow from operations of $1,578,359 for the first quarter of 2012. Our liquidity improvement quarter over quarter was primarily the result of higher product sales margins.

During the current year, we took key steps towards improving our liquidity, as follows:

(a) Improve and Generate More Consistent Margins Through Better Inventory Risk Management. We implemented an inventory risk management policy in the second quarter of 2012 wherein Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products and crude oil when our inventory levels exceed targeted levels (currently 1.5 days production). This policy helped stabilize our commodity price exposure for our refined petroleum products and crude oil inventory, which enabled us to generate a more consistent gross margin for each barrel of refined product. Our refining margins were relatively stable throughout the current year, allowing the Nixon Facility to generate an EBITDA of $1,259,012 for the current year. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Earnings Before Interest, Income Taxes and Depreciation” of this report for a reconciliation of EBITDA by business segment.
 
(b) Increase the Amount of Throughput Generated by the Nixon facility. A significant part of our business strategy is to move towards operating the Nixon Facility at or near capacity in the first half of 2013. For the current year, average throughput increased to approximately 9,700 bpd, or 65% of operating capacity. To further increase throughput, we intend to progressively ramp up throughput levels, and, on a longer-term basis, complete refurbishment of the naphtha stabilizer. See Item (c) below for additional discussion related to the naphtha stabilizer.

(c) Focus on Capital Expenditure Program to Increase Throughput and Improve Margins. We estimate costs to complete refurbishment of the naphtha stabilizer, as well as a depropanizer unit, at the Nixon Facility to be approximately $1.5 million. Refurbishment of the naphtha stabilizer and depropanizer will improve the quality of naphtha that we produce and increase the amount of throughput that can be processed by the Nixon Facility. Our ability to complete this capital expenditure project is dependent upon further advances being made by Milam under the Construction and Funding Agreement, cash from operations or third-party financing. There can be no assurance that funding will be obtained for completion of this capital expenditure project.

We continue to work with our vendors to bring our outstanding accounts payable current as expeditiously as possible. In the event that our efforts are not successful, we will experience a significant and material adverse effect on our continuing operations, liquidity and financial condition.
 

Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Our U.S. Gulf of Mexico oil and gas properties were fully impaired for the twelve months ended December 31, 2011. On November 6, 2012, we announced that BDEX entered into the Indonesia SPA with Blue Sky for the disposal of Indonesia. Operations associated with Indonesia were discontinued in 2012.  See “Part I, Item 1, Business – Ongoing Acquisition and Disposition Activities – Disposition of Working Interest in North Sumatra Basis,” as well as “Part II, Item 8. Financial Statements and Supplementary Data - Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations.

We recognized $1,184,549 of abandonment expense in the current year related to plugging and abandonment costs associated with our High Island A-7 oil and gas leasehold interest. The amount recognized reflects the amount incurred in the current year less the amount reserved for the asset retirement obligation liability, which was $141,099. We will record additional plugging and abandonment costs as information becomes available to substantiate actual and/or probable costs.

We received proceeds from the issuance of debt in the current year of $4,788,623, primarily under the Construction and Funding Agreement. Capital expenditures in the current year totaled $2,852,460, all of which related to refurbishment of the Nixon Facility. We expect to fund additional capital expenditures at the Nixon Facility primarily through the Construction and Funding Agreement, cash from operations or other borrowings. The principal balance owed to Milam under the Construction and Funding Agreement was $5,206,175 and $3,319,193, including Deficit Amounts, at December 31, 2012 and 2011, respectively.

The principal balance outstanding on the Refinery Loan, which is currently in default, was $9,298,183 and $9,669,173 at December 31, 2012 and 2011, respectively. As of the date of the filing of this report, the Refinery Loan is subject to a forbearance agreement (the "Forbearance Agreement").

As of December 31, 2102, past due principal and interest (as well as costs, fees and taxes) was $250,070. After all past due principal and interest has been paid AFNB has agreed to: (i) re-amortize the Refinery Loan to the original maturity date of October 1, 2028 and (ii) apply twelve consecutive additional monthly payments in the amount of $83,333.33 towards replenishing the $1.0 million payment reserve required under the Refinery Loan in accordance with the Forbearance Agreement.
 
The principal balance outstanding on the Notre Dame Debt note, which is currently in default, was $1,300,000 at December 31, 2012 and 2011. There are no financial covenants associated with this debt.
 
See “Part II, Item 8. Financial Statements and Supplementary Data - Note (20) Long-Term Debt” of this report for additional disclosures related to our long-term debt obligations.


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

In May 2012, we implemented an inventory risk management policy under which Genesis may, but is not required to, use derivative instruments as certain refined product inventories exceed maximum thresholds in an effort to reduce our refined petroleum products and crude oil inventory commodity price risk. However, Genesis’ execution of the inventory risk management plan is outside of our control. Accordingly, there could be situations in which Genesis fails to execute on the plan or executes on the plan in a manner that causes significant losses to us, all of which are beyond our control. In the event that our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a material and negative adverse effect on our operations, liquidity and financial condition.
 
At December 31, 2012, 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, 2012 would increase unrealized loss by approximately $30,000.

Interest Rate Risk. We are exposed to interest rate volatility with regard to existing variable rate debt tied to movements in the U.S. prime rate. At December 31, 2012, we had $9,298,183 of variable interest debt with a weighted average interest rate at year end of approximately 5.50%. At December 31, 2012, 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, 2012 would increase interest expense by approximately $92,982 per year.
 

 
 
 



 

Remainder of Page Intentionally Left Blank
 
 



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, 2012 and 2011, 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, 2012 and 2011, 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
April 1, 2013
 
Consolidated Balance Sheets
 
   
December 31,
 
   
2012
   
2011
 
             
             
             
 ASSETS
           
 CURRENT ASSETS
           
 Cash and cash equivalents
  $ 420,896     $ 1,822  
 Restricted cash
    89,593       192,004  
 Accounts receivable, net
    15,398,755       -  
 Prepaid expenses and other current assets
    228,314       58,713  
 Deposits
    1,236,447       473,026  
 Inventory
    2,300,692       4,533,961  
 Total current assets
    19,674,697       5,259,526  
                 
 Property, plant and equipment, net
    35,862,085       32,307,929  
                 
 Debt issue costs, net
    532,335       566,133  
 Other assets
    9,463       10,468  
 Trade name
    303,346       -  
                 
 TOTAL ASSETS
  $ 56,381,926     $ 38,144,056  
                 
 LIABILITIES AND STOCKHOLDERS' EQUITY
               
                 
 CURRENT LIABILITIES
               
 Accounts payable
  $ 19,171,013     $ 4,841,859  
 Accounts payable, related party
    1,594,021       908,139  
 Note payable
    43,941       46,318  
 Accrued expenses and other current liabilities
    725,238       744,921  
 Interest payable, current portion
    640,352       995,916  
 Long-term debt, current portion
    1,816,960       1,839,501  
 Total current liabilities
    23,991,525       9,376,654  
                 
 Long-term liabilities:
               
 Asset retirement obligations
    921,260       -  
 Long-term debt, net of current portion
    13,989,517       12,455,102  
 Long-term interest payable, net of current portion
    858,784       650,214  
 Total long-term liabilities
    15,769,561       13,105,316  
                 
 TOTAL LIABILITIES
    39,761,086       22,481,970  
                 
 Commitments and contingencies
               
                 
 STOCKHOLDERS' EQUITY
               
 Common stock ($0.01 par value, 20,000,000 shares authorized, 10,563,297 and 8,426,456
    105,633       84,265  
 shares issued and outstanding at December 31, 2012 and December 31, 2011, respectively)
               
 Additional paid-in capital
    36,524,142       17,302,124  
 Accumulated deficit
    (20,008,935 )     (1,724,303 )
 Total stockholders' equity
    16,620,840       15,662,086  
                 
 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
  $ 56,381,926     $ 38,144,056  
 
See accompanying notes to condensed consolidated financial statements.
 
 
Consolidated Statements of Operations
 
   
Twelve Months Ended December 31,
 
   
2012
   
2011
 
             
REVENUE FROM OPERATIONS
           
Refined product sales
  $ 351,665,234     $ -  
Pipeline operations
    406,812       -  
Oil and gas sales
    22,668       -  
                 
Total revenue from operations
    352,094,714       -  
                 
COST OF OPERATIONS
               
Cost of refined products sold
    342,035,755       -  
Refinery operating expenses
    8,603,155       -  
Pipeline operating expenses
    391,169       -  
Lease operating expenses
    57,122       -  
General and administrative expenses
    2,076,946       645,444  
Depletion, depreciation and amortization
    1,622,864       17,684  
Abandonment expense
    1,184,549       -  
Impairment expense
    9,435,745       -  
Bad debt expense
    9,508       -  
Accretion expense
    105,032       -  
Loss on disposal of property and equipment
    5,665       -  
                 
Total cost of operations
    365,527,510       663,128  
                 
Loss from operations
    (13,432,796 )     (663,128 )
                 
OTHER INCOME (EXPENSE)
               
Net tank rental revenue
    534,047       874,421  
Interest and other income
    21,940       23,901  
Interest expense
    (954,579 )     (51,340 )
Total other income (expense)
    (398,592 )     846,982  
                 
Income (loss) from continuing operations before income taxes
    (13,831,388 )     183,854  
Tax expense
               
Current
    (9,678 )     -  
Deferred
    -       -  
Income tax expense
    (9,678 )     -  
Income (loss) from continuing operations, net of tax
  $ (13,841,066 )   $ 183,854  
                 
Loss from discontinued operations, net of tax
  $ (4,443,566 )   $ -  
Net income (loss)
  $ (18,284,632 )   $ 183,854  
                 
Basic earnings (loss) per common share
               
Continuing operations
  $ (1.35 )   $ 0.02  
Discontinued operations
  $ (0.43 )   $ -  
Basic earnings (loss) per common share
  $ (1.78 )   $ 0.02  
                 
Diluted earnings (loss) per common share
               
Continuing operations
  $ (1.35 )   $ 0.02  
Discontinued operations
  $ (0.43 )   $ -  
Diluted earnings (loss) per common share
  $ (1.78 )   $ 0.02  
                 
Weighted average number of common shares outstanding:
               
Basic
    10,284,152       8,426,456  
Diluted
    10,284,152       8,426,456  
 
See accompanying notes to condensed consolidated financial statements.
 
 
Consolidated Statements of Stockholders’ Equity
 
   
Common
         
Additional
         
Total
 
   
Stock
   
Common
   
Paid-In
   
Accumulated
   
Stockholders’
 
   
Shares
   
Stock
   
Capital
   
Deficit
   
Equity
 
                               
Balance at December 31, 2010
    8,426,456     $ 84,265     $ 17,302,124     $ (1,908,151 )   $ 15,478,238  
                                         
Net income
    -       -       -       183,854       183,854  
                                         
Balance at December 31, 2011
    8,426,456       84,265       17,302,124       (1,724,303 )     15,662,086  
                                         
Common stock issued for acquisition
    2,098,390       20,984       18,025,170       -       18,046,154  
Conversion of LE's related party accounts
                                    -  
payable to equity on acquisition
    -       -       993,732       -       993,732  
Common stock issued for services
    30,288       303       183,197       -       183,500  
Common stock issued to exercise options
    8,163       81       19,919       -       20,000  
Net loss
    -       -       -       (18,284,632 )     (18,284,632 )
                                         
Balance at December 31, 2012
    10,563,297     $ 105,633     $ 36,524,142     $ (20,008,935 )   $ 16,620,840  

 
 
Remainder of Page Intentionally Left Blank


 
Consolidated Statements of Cash Flows
 
   
Twelve Months Ended December 31,
 
   
2012
   
2011
 
OPERATING ACTIVITIES
           
   Net income (loss)
  $ (18,284,632 )   $ 183,854  
   Loss from discontinued operations
    4,443,566       -  
   Adjustments to reconcile net income (loss) to net cash
               
provided by (used in) operating activities:
               
Depletion, depreciation and amortization
    1,611,708       17,684  
Impairment expense
    9,435,745       -  
Unrealized loss on derivatives
    136,100       -  
Amortization of debt issue costs
    33,799       33,799  
Amortization of intangible assets
    10,468       (10,468 )
Accretion expense
    105,032       -  
Abandonment expense
    503,454       -  
Common stock issued for services
    163,499       -  
Bad debt expense
    9,508       -  
Changes in operating assets and liabilities (net of effects of acquisition in 2012)
 
Restricted cash
    102,411       33,797  
Accounts receivable
    (14,724,996 )     -  
Prepaid expenses and other current assets
    43,894       (58,712 )
Deposits
    (763,421 )     (397,407 )
Inventory
    2,288,436       (4,484,521 )
Accounts payable, accrued expenses and other liabilities
    12,160,088       4,950,484  
Accounts payable, related party
    3,228,128       (16,227 )
Net cash provided by operating activities - continuing operations
    502,787       252,283  
Net cash used in operating activities - discontinued operations
    (435,460 )     -  
Net cash provided by operating activities
    67,327       252,283  
                 
INVESTING ACTIVITIES
               
Capital expenditures
    (2,852,460 )     (3,507,850 )
Cash acquired on acquisition
    1,674,709       -  
Net cash used in investing activities
    (1,177,751 )     (3,507,850 )
                 
FINANCING ACTIVITIES
               
Proceeds from issuance of debt
    4,788,623       3,304,300  
Payments on long term debt
    (3,276,748 )     (42,610 )
Proceeds from notes payable
    24,548       -  
Payments on notes payable
    (26,925 )     (5,034 )
Proceeds from excercse of stock options
    20,000       -  
Net cash provided by financing activities
    1,529,498       3,256,656  
                 
Net increase in cash and cash equivalents
    419,074       1,089  
                 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    1,822       733  
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 420,896     $ 1,822  
                 
Supplemental Information:
               
Non-cash investing and financing activities:
               
Related party payable converted to equity
  $ 993,732     $ -  
Issuance of stock for acquisition of Blue Dolphin at fair value, inclusive
               
of cash acquired of $1,674,709
  $ 18,046,154     $ -  
Accrued services payable converted to common stock
  $ 183,500     $ -  

See accompanying notes to consolidated financial statements.
 
 
Notes to Consolidated Financial Statements
 
(1)
Organization

Company Operations
 
Blue Dolphin Energy Company (referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “we,” “us” and “our”), a Delaware corporation, was formed in 1986 as a holding company and conducts substantially all of its operations through its wholly-owned subsidiaries. Our operating subsidiaries include:
 
-  
Lazarus Energy, LLC (“LE”), a Delaware limited liability company (petroleum processing assets);
 
-  
Lazarus Refining & Marketing, LLC (“LRM”), a Delaware limited liability company (petroleum storage and terminaling);
 
-  
Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations);
 
-  
Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities);
 
-  
Blue Dolphin Services Co., a Texas corporation (administrative services);
 
-  
Blue Dolphin Exploration Company (“BDEX”), a Delaware corporation (exploration and production investment); and
 
-  
Petroport, Inc., a Delaware corporation (inactive).
 
Effective February 15, 2012, Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE from Lazarus Energy Holdings, LLC (“LEH”), a Delaware limited liability company (the “LE Acquisition”). The LE Acquisition was accounted for as a reverse merger using accounting principles applicable to reverse acquisitions whereby the financial statements subsequent to the date of the transaction are presented as a continuation of LE (the legal subsidiary). See “Note (4) LE Acquisition” of this report for further information related to the LE Acquisition.
 
 (2)
Basis of Presentation

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

 (3)
Significant Accounting Policies

The summary of significant accounting policies of Blue Dolphin Energy Company is presented to assist in understanding our consolidated financial statements. The consolidated financial statements and notes are representations of our management who is responsible for their integrity and objectivity. These accounting policies conform to generally accepted accounting principles and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these audited consolidated financial statements in conformity with GAAP. While we believe current estimates are reasonable and appropriate, actual results could differ from those estimated.
 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements
(Continued)
Cash and Cash Equivalents

Cash equivalents include liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Restricted Cash
 
Restricted cash was $89,593 and $192,004 at December 31, 2012 and 2011, respectively. These amounts relate to escrow accounts for potential environmental matters and loan repayments.

Accounts Receivable, Allowance for Doubtful Accounts and Concentrations 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 receivables for collectability and establish an allowance as necessary for individual customer balances.

Concentration of Risk

Financial instruments that potentially subject us to concentrations of credit risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at banks located in Houston, Texas. Accounts in the United States are insured by the Federal Deposit Insurance Corporation up to $250,000. At December 31, 2012 and 2011, we had uninsured balances of $170,896 and $0, respectively.

We had 4 customers that accounted for approximately 84% of our total revenue for the twelve months ended December 31, 2012. These 4 customers represented approximately $11.4 million of accounts receivable at December 31, 2012.

Inventory

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

Price-Risk Management Activities

In May 2012, we implemented an inventory risk management policy under which Genesis Energy, LLC (“Genesis”) may, but is not required to, use derivative instruments as economic hedges to reduce refined petroleum products and crude oil inventory commodity price risk. We follow FASB ASC guidance for derivatives and hedging related to stand alone derivative instruments. These contracts are not subject to hedge accounting treatment under FASB ASC guidance. Accordingly, even though such hedge positions are direct contractual obligations of Genesis and not us, we nevertheless record the fair value of these Genesis hedges in our condensed consolidated balance sheet each quarter because of contractual arrangements between Genesis and us under which we are effectively exposed to the potential gains or losses. Changes in the fair value from quarter to quarter are recognized in our condensed consolidated statement of operations.
 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements
(Continued)
 
Property and Equipment
 
Refinery and Facilities. Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are charged to expense as incurred. Management expects to continue making improvements to our refinery assets 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 over the estimated useful lives of 25 years 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, 2012 and 2011.

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our U.S. Gulf of Mexico oil and gas properties were uneconomic for the twelve months ended December 31, 2012 due to leases being relinquished and fields being shut-in by operators. Operations associated with Indonesia were discontinued in 2012. See “Note (14) Discontinued Operations” of this report for additional disclosures related to Indonesia and discontinued operations. The estimated fair values of our AROs related to our oil and gas properties were recorded in connection with the LE Acquisition.

Pipelines and Facilities Assets. Pipelines and facilities assets are recorded at cost. 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.  The estimated fair values of our AROs related to our pipeline and facilities assets were recorded in connection with the LE Acquisition.

Construction in Progress. Construction in progress expenditures, insurance, interest and other costs related to refurbishment activities at the Nixon Facility are capitalized as incurred. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the Nixon Facility. Depreciation begins once the asset is placed in service.

Intangibles – Goodwill and Other

Goodwill. We recognized goodwill in connection with our reverse merger with LE. Goodwill has an indefinite useful life and represents the difference between the total purchase price and the fair value of assets (tangible and intangible) and liabilities at the date of acquisition is reviewed for impairment annually, and more frequently as circumstances warrant, and written down only in the period in which the recorded value of such assets exceed their fair value. We do not amortize goodwill in accordance with Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance related to intangibles, goodwill and other. We perform an impairment test annually.
 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements
(Continued)
 
Goodwill is tested for impairment at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which discrete financial information with similar economic characteristics is available and the operating results are regularly reviewed by management. Our pipeline transportation and oil and gas exploration and production business segments comprise the reporting units for goodwill impairment testing purposes.
 
In 2012, we adopted FASB Accounting Standards Updates (“ASU”) related to testing goodwill for impairment,” in connection with the performance of our annual goodwill impairment testing. Under the ASU guidance, entities are provided with the option of first performing a qualitative assessment on none, some or all of its reporting units to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If after completing a qualitative analysis, it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value a quantitative analysis is required.

The quantitative goodwill impairment analysis is a two-step process. We performed step one quantitative testing for our pipeline transportation and oil and gas exploration and production business segments in 2012. The first step used to identify potential impairment involves comparing each reporting unit’s estimated fair value to its carrying value, including goodwill. During the first step, we evaluated goodwill for impairment using a business valuation method, which is calculated as of a measurement date by determining the present value of debt-free, after-tax projected future cash flows, discounted at the weighted average cost of capital of a hypothetical third party buyer. Our analysis indicated an impairment in 2012.

The second step of the process involves the calculation of an implied fair value of goodwill for each reporting unit for which step one indicated impairment. The implied fair value of goodwill is determined by measuring the excess of the estimated fair value of the reporting unit over the estimated fair values of the individual assets, liabilities and identifiable intangibles as if the reporting unit was being acquired in a business combination. If the implied fair value of goodwill exceeds the carrying value of goodwill assigned to the reporting unit, there is no impairment. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment charge is recorded for the excess. An impairment loss cannot exceed the carrying value of goodwill assigned to a reporting unit and the subsequent reversal of goodwill impairment losses is not permitted. The determination of fair value required us to make significant estimates and assumptions. These estimates and assumptions primarily included, but were not limited to, revenue growth and operating earnings projections, discount rates, growth rates and required capital expenditure projections. Due to the inherent uncertainty involved in making these estimates, actual results could have differed materially from our estimates. As a result of our evaluation, we recognized a non-cash impairment charge of $1,445,720 related to goodwill.

Other Intangible Assets.  We recognized trade name in connection with our reverse merger with LE. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, intangible assets with indefinite lives are tested annually for impairment. Management performed its regular annual impairment testing of trade name following FASB ASC guidance for determining impairment. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2012.
 
 
Blue Dolphin Energy Company & Subsidiaries
Notes to Consolidated Financial Statements
(Continued)
 
Debt Issue Costs

We have debt issue costs related to certain of our long-term debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations. Debt issue costs exclusive of amortization were $675,980 at December 31, 2012 and 2011. Accumulated amortization in the amount of $143,645 and $109,847 at December 31, 2012 and 2011, respectively, are being amortized over the life of the Refinery Loan. Amortization expense, which is included in interest expense, was $8,450 for the years ended December 31, 2012 and 2011. Amortization expense was $25,349 for the years ended December 31, 2012 and 2011. See “Note (20) Long-Term Debt” of this report for additional disclosures related to the Refinery Loan.
 
Revenue Recognition

Refined Petroleum Products Revenue. We sell various refined petroleum products including naphtha, distillates and atmospheric gas oil. Revenue from refined product sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured.

Customer 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 Storage Rental Revenue. Revenue from tank storage rental is recorded on a straight line basis in accordance with the terms of the related lease agreement.  The lessee is invoiced monthly for the amount of rent due for the related period.

Recognition of Oil and Gas Revenue. Sales from producing wells are recognized on the entitlement method of accounting, which defers recognition of sales when, and to the extent that, deliveries to customers exceed our net revenue interest in production. Similarly, when deliveries are below our net revenue interest in production, sales are recorded to reflect the full net revenue interest. Our imbalance liability at December 31, 2012 was not material.