ITEM 1. BUSINESS
On February 15 2012, we acquired Lazarus Energy, LLC, a Delaware limited liability company (“LE”) pursuant to a merger that has the potential to expand the size and scope of our business (the “Acquisition”). Except as otherwise noted, the description of our business contained in this Item 1 refers to the business of Blue Dolphin and its consolidated subsidiaries on a pre-acquisition basis. Further, the financial results contained in this report, which is for the twelve month period ended December 31, 2011, do not include any results from our crude oil and condensate processing operations which we acquired as part of the Acquisition.
The Company
Blue Dolphin, a Delaware corporation formed in 1986, manages the investments and conducts the operations of its wholly-owned subsidiaries. At December 31, 2011, Blue Dolphin operated two lines of business through its subsidiaries: (i) pipeline transportation services to producers/shippers and (ii) oil and gas exploration and production.
At December 31, 2011, Blue Dolphin’s subsidiaries were as follows:
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Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”) (pipeline operations);
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Blue Dolphin Petroleum Company, a Delaware corporation (“BDPC”) (exploration and production activities);
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Blue Dolphin Exploration Company, a Delaware corporation (inactive);
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Blue Dolphin Services Co., a Texas corporation (administrative services); and
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Petroport, Inc., a Delaware corporation (inactive).
Our principal executive office is located at 801 Travis Street, Suite 2100, Houston, Texas, 77002, and our telephone number is (713) 568-4725. At December 31, 2011, we had five (5) full-time employees at locations in Freeport and Houston, Texas and regularly used the services of one (1) consultant. Our common stock, par value $0.01 per share (“Common Stock”) is publicly traded on the OTCQX U.S. Premier under the ticker symbol “BDCO” Our corporate website address is http://www.blue-dolphin.com.
Certain terms that are commonly used in the oil and gas industry, including terms that define our rights and obligations with respect to our interests in properties, are defined in the “Glossary of Certain Oil and Gas Terms” of this report.
Recent Developments
Acquisition of Lazarus Energy, LLC (“LE”). As previously reported, we entered into a Purchase and Sale Agreement (the “PSA”) with Lazarus Energy Holdings, LLC, a Delaware limited liability company (“LEH”) and LEH’s wholly-owned subsidiaries to acquire one hundred percent (100%) of the issued and outstanding membership interests of LE, (the “Acquisition”). LE’s primary asset is a 56-acre crude oil processing facility, located near Nixon, Texas (the “Nixon Facility”). On February 15, 2012, we consummated the Acquisition and issued, in reliance on the exemption provided by Section 4(2) of the Securities Act 8,393,560 shares of Common Stock, subject to anti-dilution adjustments, to LEH as consideration for LE (the “Original BDEC Shares”). Additionally, on February 21, 2012, pursuant to the anti-dilution provisions contained in the PSA, and in reliance on the exemption provided by Section 4(2) of the Securities Act, we issued 32,896 shares of Common Stock to LEH (the “Anti-Dilution Shares” and together with the Original BDEC Shares, the “BDEC Shares”) effective February 15, 2012. As a result of our issuance of the BDEC Shares, LEH currently owns eighty percent (80%) of our issued and outstanding Common Stock. The issuance of the BDEC Shares to LEH resulted in a change in control of Blue
Index to Financial Statements
Dolphin. Further, pursuant to the terms of the PSA, the composition of Blue Dolphin’s Board of Directors (the “Board”) and management changed. The Acquisition will be accounted for as a “reverse acquisition” in which LE is deemed to be the “Acquirer” and accounting predecessor and Blue Dolphin is deemed to be the “Acquiree.” Following the Acquisition, the combined company will continue to operate under the name Blue Dolphin Energy Company. See our Current Reports on Form 8-K filed with the Securities and Exchange Commission on July 22, 2011, February 2, 2012, February 21, 2012, February 28, 2012 and March 14, 2012, for more information on the Acquisition.
Management of Blue Dolphin’s Assets. As part of LEH’s assignment of the membership interests of LE, on February 15, 2012, Blue Dolphin, LE and LEH entered into a Management Agreement (the “Management Agreement”) pursuant to which LEH agreed to manage and operate the Nixon Facility and Blue Dolphin’s other operations (collectively, the “Services”). Pursuant to the terms of the Management Agreement, LEH shall retain, as compensation for the Services, the right to receive (i) weekly payments based on revenues from the sale of diesel blend stocks processed by the Nixon Facility not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of LE’s financial statements 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 processed at the Nixon Facility during the term of the Management Agreement, to the extent the quantity exceeds 10,000 barrels per day determined on a monthly basis. We further 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 a third party dated August 12, 2011, 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 may be terminated if the Board determines that the Management Agreement is no longer in the best interest of Blue Dolphin.
LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock. 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 Chief Financial Officer, 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. See “Part I, Item 1A.
ITEM 1A. RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks we face. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.
Index to Financial Statements Risks Related to our Business
The success of our acquisition of LE will depend on our ability to realize the anticipated benefits from integrating LE’s business into our operations.
We may fail to realize the anticipated benefits from this integration on a timely basis, or at all, for a variety of reasons, including the following:
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difficulties expanding in new markets or geographies where we have no or limited direct prior experience;
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failure to identify or assess the magnitude of certain liabilities we assumed in the acquisition, which could result in unexpected litigation or regulatory exposure, unfavorable accounting treatment, unexpected increases in taxes due, a loss of anticipated tax benefits or other adverse effects on our business, operating results or financial condition;
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difficulties or delays in incorporating acquired technologies or integrating overall operations and business systems while maintaining uniform standards, controls, processes and policies;
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failure to successfully manage relationships with our combined supplier and customer base; and
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difficulties in modifying LE’s existing accounting and internal control systems to comply with Section 404 of the Sarbanes-Oxley Act of 2002, to which LE is not currently subject, which could adversely impact the effectiveness of internal control over financial reporting for the combined company.
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 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 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 products, our operating results could suffer.
Selling refined products to the wholesale market is an important part of our business, and as our refined 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 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 products offered by our competitors.
We are dependent on third-party operators for the transportation of crude oil into and refined 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 products to wholesale markets could be materially and adversely affected.
Index to Financial Statements We rely on trucks for the receipt of crude oil into and the sale of refined 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 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.
Our operations, including our operation of the Nixon Facility, subject us to the inherent risk of incurring significant environmental costs and liabilities.
There is inherent risk of incurring significant environmental costs and liabilities in the operation of the Nixon Facility due to our handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to our operations, and as a result of historical operations and waste disposal practices of prior owners of our facilities. We currently own or operate properties that for many years have been used for industrial activities, including refining or terminal storage operation. Private parties, including the owners of properties adjacent to our operations and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance or other sources of indemnity. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, and results of operations.
Our relationship with LEH and our related party transactions with LEH and its affiliates may cause conflicts of interest that may adversely affect us.
LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock. 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 Chief Financial Officer, 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 has no fiduciary duty to make decisions in our best interest. 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
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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.
LEH holds a significant interest in us.
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.
Declines in throughput volumes and production rates from our leasehold properties in the U.S. Gulf of Mexico are expected to continue.
In recent years, throughput volumes on our pipelines and production rates from our leasehold properties in the U.S. Gulf of Mexico have continued to decline as a result of decreased activity in the U.S. Gulf of Mexico and depleting reserves. Following the April 2010 Deepwater Horizon explosion and oil spill, regulators have continued to move slowly in issuing new drilling permits in the U.S. Gulf of Mexico. This has negatively impacted our ability to attract new producers/shippers to our pipelines and make additional investments in new oil and gas properties. Although our U.S. Gulf of Mexico oil and gas properties may continue to operate over the next twelve to eighteen months, we expect the operating costs to exceed gross revenues based on current reserves and net cash flow estimates making these properties uneconomic.
During the past year, we have been primarily dependent on revenue from one key customer.
As a result of decreased revenue from pipeline operations and oil and gas sales related to our U.S. Gulf of Mexico leasehold interests, revenue from the North Sumatra Basin-Langsa Field accounted for approximately 54% of our total revenue in 2011 compared to approximately 26% in 2010. Unless we are able to offset this revenue with revenue from the sale of refined products, transportation throughput, interests in other oil and gas properties or other revenue generating assets at an acceptable cost, our financial condition could be materially adversely affected if production from the North Sumatra Basin-Langsa Field declines sharply or ceases.
If we are not able to generate sufficient funds from operations or obtain financing from other sources, we may not be able to continue our operations.
In recent years we have used a portion of our cash reserves to fund working capital requirements that were not funded from our operations. Continued pipeline underutilization, low commodity prices, production problems, reserve declines, unfavorable drilling results and other factors beyond our control could further reduce funds from our operations. Currently, we project that our current cash reserves will be sufficient to meet our obligations. If we are unable to realize the benefits of our acquisition of LE or obtain additional funds, we may have to seek debt and/or equity financing to meet our working capital requirements. Our history of losses may affect our ability to raise additional capital and increase the cost and terms of obtaining such financing. In the event we are not able to raise additional capital, we may be forced to sell our assets or discontinue our operations.
A substantial and extended decline in the prices of oil or gas would have a material adverse effect on our operations.
Our revenue, profitability, operating cash flow and potential for growth are largely dependent on prevailing oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include:
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weather conditions;
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the domestic and international economy;
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Organization of Petroleum Exporting Countries’ actions;
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governmental regulation;
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political stability in the Middle East, South America and elsewhere;
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foreign supply of oil and natural gas;
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price of foreign imports;
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availability of alternate fuel sources; and
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the value of the U.S. dollar in relation to other currencies.
In addition, low or declining oil and natural gas prices could have collateral effects that could adversely affect us, including the following:
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reducing the exploration for and development of oil and gas by third-party companies operating in the vicinity of our pipeline systems;
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increasing our dependence on external sources of capital to meet our cash needs; and
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impairing our ability to obtain needed capital.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Estimating reserves of oil and gas is complex. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, including oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
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the quality and quantity of available data;
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the interpretation of that data;
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the accuracy of various mandated economic assumptions; and
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the judgment of the persons preparing the estimate.
The proved reserve information set forth in this report is based on estimates prepared by third-party petroleum engineering consulting firms based on information that we provided. Although our U.S. Gulf of Mexico oil and gas properties may continue to operate over the next twelve to eighteen months, we expect the operating costs to exceed gross revenues based on current reserves and net cash flow estimates making these properties uneconomic. Actual quantities of recoverable oil and gas reserves, future production, oil and gas prices, taxes, development expenditures, abandonment costs and operating expenses prepared by others will likely vary from these estimates. Any significant variance could materially affect the quantities and net present value of our reserves. Furthermore, the present value of future net cash flows will most likely not equate to the current market value of their estimated proved oil and gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves were based on the historical 12-month average price (based on the first of the month pricing for the most recently ended fiscal year) and costs in effect at December 31, 2011. Actual future prices and costs may be materially different from the prices and costs they used.
We cannot control the activities on properties we do not operate.
Currently, third parties operate or control the development and operation of the oil and gas properties in which we have an interest. As a result, we depend on these third-parties to properly conduct lease acquisition, drilling, completion and production operations. The failure of any such third party operator or drilling contractors, as well as other service providers working on their behalf, to properly perform services or to act in ways that are in our best interest, could adversely affect our interests.
Index to Financial Statements We own and generally anticipate that we will continue to own substantially less than a 50% working interest in our oil and gas prospects and properties and will therefore engage in joint operations with other working interest owners. Since we own or control less than a majority of the working interest, decisions affecting our interest could be made by the owners of a majority of the working interest. For instance, if we are unwilling or unable to participate in the costs of operations approved by owners of a majority of the working interests in a well, our working interest in the well (and possibly other wells on the property) will likely be subject to contractual “non-consent penalties.” These penalties may include, full or partial forfeiture of our interest in the well or a relinquishment of our interest in production from the well in favor of the participating working interest owners until the participating working interest owners have recovered a multiple of the costs which would have been borne by us if we had elected to participate, which often ranges from 400% to 600% of such costs.
The geographic concentration of our assets may have a greater effect on us compared to other companies.
The majority of our onshore assets are located in the eagle Ford Shale and Gulf Coast areas of Texas, while the majority of our offshore assets are located in the U.S. Gulf of Mexico. As a result, we are at a greater risk of being impacted by local and regional conditions compared to oil and gas companies that have their assets more geographically diversified. Any negative regional event, including commodity price fluctuations, natural disasters and restrictive governmental regulations could adversely impact our business.
Strong competition from larger companies may negatively impact our ability to continue our operations.
The oil and gas industry is highly competitive. Our competitors include major integrated oil and gas companies, large independent energy companies, affiliates of major interstate and intrastate pipelines and national and local refinery operators and gatherers, many of which possess greater financial and other resources than we do. Our ability to successfully compete in the marketplace is affected by many factors, including our ability to access capital and absorb risks. We believe these factors largely put us at a competitive disadvantage in consummating transactions and acquiring new assets.
We intend to continue pursuing acquisitions. Our business may be adversely affected if we cannot effectively integrate acquired operations.
One of our business strategies is to acquire operations that are complementary to our existing business operations. The evaluation of opportunities involves time and expense, and acquiring operations and assets involves financial, operational and legal risks, including, but not limited to:
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inadvertently becoming subject to liabilities of the acquired company that were unknown to us at the time of the acquisition, such as later asserted litigation matters or tax liabilities;
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the difficulty of assimilating operations, systems and personnel of the acquired businesses; and
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maintaining uniform standards, controls, procedures and policies.
Competition from other potential buyers could cause us to pay a higher price than we otherwise might have paid and reduce our acquisition opportunities. We are often out-bid by larger, better capitalized companies for the acquisition opportunities that we pursue.
Operating hazards may adversely affect our ability to conduct business.
Our operations are subject to inherent risks normally associated with oil and gas operations, including, but not limited to:
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fires and explosions;
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pollution;
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pipeline ruptures;
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sudden violent expulsions of oil, gas and mud while drilling a well, commonly referred to as a blowout;
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a cave in and collapse of the earth’s structure surrounding a well, commonly referred to as cratering; and
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other environmental risks.
If any of these events were to occur, we could suffer substantial losses from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. 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 pipelines and other assets face operating hazards, and the potential limits on insurance coverage could expose us to potentially significant liability costs.
Our pipelines, exploration and production and other assets are subject to certain operating hazards, and our cash flow from those operations, if any, could decline as a result of a major accident, explosion or fire, 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.
Compliance with environmental and other government regulations could be costly and could negatively impact our operations.
Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:
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require the acquisition of a permit before operations can be commenced;
Index to Financial Statements
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restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;
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limit or prohibit drilling and pipeline activities on certain lands lying within wilderness, wetlands and other protected areas;
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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and abandoning pipelines; and
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impose substantial liabilities for pollution resulting from our operations.
The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and gas industry in general.
Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, including limited coverage for sudden and accidental environmental damages. However, we do not believe that insurance coverage for all environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue to operate our properties if certain environmental damages occur.
The EPA imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the EPA, could have a material adverse impact on us.
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 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.
Index to Financial Statements
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Information appearing in “Item 1. Business” describing our business activities is incorporated herein by reference.
Our principal executive office, which is leased, is located at 801 Travis Street, Suite 2100, Houston, Texas 77002.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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 Acquisition. LEH has 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 has 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.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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Index to Financial Statements PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Price for Common Stock
Our Common Stock is quoted on the OTCQX U.S. Premier tier under the ticker symbol “BDCO.” As of March 30, 2012, we had 292 record holders of our Common Stock. Based on the record date for our 2011 annual meeting of stockholders, which was held on January 27, 2012, we had approximately 3,000 beneficial holders of our Common Stock.
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.
(1) Prices for September 30, June 30 and March 31, 2010 have been adjusted to reflect our 1-for-7 reverse stock split, which occurred in the quarter ended September 30, 2010.
(2) 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” See “Recent Developments” in “Part I, Item 1. Business” of this report for additional information related to Nasdaq’s decision to delist our Common Stock.
Dividend Policy
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.
Index to Financial Statements Equity Compensation Plan Information
The following table provides information for all equity compensation plans as of the fiscal year ended December 31, 2011, under which our equity securities were authorized for issuance:
Securities Authorized for Issuance under Equity Compensation Plans
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ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
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ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a review of certain aspects of our financial condition and results of operations and should be read in conjunction with “Item 1, Business” and “Item 8, Financial Statements and Supplementary Data,” as well as the “Notes to Consolidated Financial Statements.”
Executive Summary
As of December 31, 2011, we operated two lines of business through our subsidiaries: (i) pipeline transportation services to producers/shippers, and (ii) oil and gas exploration and production. Our pipeline assets are located primarily offshore in the Texas Gulf Coast area and our leasehold interests in properties are located in the U.S. Gulf of Mexico and the North Sumatra Basin offshore Indonesia.
Pipeline Operations.
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BDPS - The BDPS is currently transporting an aggregate of approximately 3 MMcf of gas per day, which represents 1% of throughput capacity.
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GA 350 - The GA 350 is currently transporting an aggregate of approximately 9 MMcf of gas per day, which represents 14% of throughput capacity.
Exploration and Production.
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North Sumatra Basin-Langsa Field - The H-4 Well is currently producing approximately 370 barrels of oil per day.
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High Island Block 115 - The B-1 ST2 Well is currently producing approximately 2 MMcf of gas per day.
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Galveston Area Block 321 - The A-4 Well is currently producing approximately 2 MMcf of gas per day.
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High Island Block 37 - The block contains no active wells.
In recent years, throughput volumes on our pipelines and production rates from our leasehold properties in the U.S. Gulf of Mexico have continued to decline as a result of decreased activity in the Gulf of Mexico and depleting reserves. Following the April 2010 Deepwater Horizon explosion and oil spill, regulators have moved slowly to issue new drilling permits in the Gulf of Mexico. This has negatively impacted our ability to attract new producers/shippers to our pipelines and to acquire additional leasehold interests. Although our U.S. Gulf of Mexico oil and gas properties may continue to operate over the next twelve to eighteen months, we expect the operating costs to exceed gross revenues based on current reserves and net cash flow estimates making these properties uneconomic. As a result of the Acquisition, we anticipate that our core focus going forward will be crude oil and condensate processing.
Index to Financial Statements Results of Operations
For the year ended December 31, 2011 (the “current period”), we reported net income of $617,935 compared to a net loss of $1,022,895 for the year ended December 31, 2010 (the “previous period”). For the three months ended December 31, 2011 (the “current quarter”), we reported a net loss of $1,059,577 compared to a net loss of $58,122 for the three months ended December 31, 2010 (the “previous quarter”).
2011 Compared to 2010
Revenue from Pipeline Operations. Revenue from pipeline operations decreased by $947,386, or 50%, in the current period to $931,500. Revenue in the current period from the BDPS totaled approximately $659,500 compared to approximately $1,538,000 in the previous period primarily due to lower volumes of transported gas. Daily gas volumes transported through the BDPS averaged approximately 5 MMcf of gas per day in the current period compared to approximately 14 MMcf of gas per day in the previous period. Revenue on the GA 350 decreased by approximately $69,000 to approximately $272,000 in the current period primarily due to natural production declines. Daily gas volumes transported through the GA 350 decreased to approximately 14 MMcf of gas per day in the current period from approximately 17 MMcf of gas per day in the previous period.
Revenue from Oil and Gas Sales. Revenue from oil and gas sales increased by $480,033, or 56%, to $1,342,718 in the current period primarily due to production from the North Sumatra Basin-Langsa Field.
Our average realized gas price per Mcf in the current period was $3.71 compared to $3.85 in the previous period. The sales mix by product was 93% oil and 7% gas. Our average realized price per barrel of oil was $118.59 in the current period compared to $88.14 in the previous period.
Revenue breakdown for the current period by field was approximately $1,222,400 for the North Sumatra Basin-Langsa Field, $84,200 for High Island Block 115, $26,900 for Galveston Area Block 321 and $9,200 for High Island Block 37. Revenue breakdown for the previous period by field was approximately $720,300 for the North Sumatra Basin-Langsa Field, $48,900 for High Island Block 115, $48,200 for Galveston Area Block 321 and $45,300 for High Island Block 37.
Pipeline Operating Expenses. Pipeline operating expenses decreased by $89,738, or 8%, to $1,008,859 in the current period. The decrease was primarily due to decreases in insurance expense, chemicals, saltwater disposal transportation costs, property taxes and other operating expenses. The decreases were partially offset by an increase in legal expenses, related to the sale of the Buccaneer Pipeline.
Lease Operating Expenses. Lease operating expenses increased $500,484, or 74%, in the current period to $1,174,252 primarily due to expenses from the North Sumatra Basin-Langsa Field. Lease operating costs associated with North Sumatra Basin-Langsa Field totaled approximately $1,098,500 for the current period.
Depletion, Depreciation and Amortization. Depletion, depreciation and amortization decreased by $27,402, or 4%, in the current period to $591,927 primarily due to lower depletion of the North Sumatra Basin-Langsa Field.
Impairment of Oil and Gas Properties. We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, calculated using prevailing oil and natural gas prices on the last day of the period, or a subsequent higher price under certain circumstances. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. Our ceiling for the current period was
Index to Financial Statements calculated using domestic prices of $96.04 per barrel of oil and $4.18 per Mcf of gas and an international price of $114.95 per barrel of oil. At December 31, 2011, our costs exceeded our ceiling limitation, resulting in a write-down of our U.S. Gulf of Mexico oil and gas properties of $252,706. Our ceiling for the previous period was calculated using prices of $79.61 per barrel of oil and $4.33 per Mcf of gas.
General and Administrative Expenses and Stock Based Compensation. General and administrative expenses and stock based compensation expenses increased by $146,561, or 10%, in the current period to $1,574,364 primarily due to increases in franchise tax, employee bonuses, employee insurance, shareholder reporting expenses and software maintenance fees. The increases were partially offset by decreases in officer salaries, consulting and audit expense.
Gain on Sale of Property and Equipment. During the current period, BDPL sold its eighty-three and one-third percent (83 1/3%) undivided interest in the Buccaneer Pipeline to Sunoco for proceeds of approximately $3.6 million in cash. The gain on the sale was approximately $3.1 million
Recovery of Allowance for Doubtful Loan Receivable. Recovery for allowance for doubtful loan receivable reduced by $201,000 in the current period primarily due to the addition of a disposal well, with a fair market value of $201,000, which was recorded as a recovery of a bad debt expense on an outstanding loan receivable, net of credited and recovered amounts in the previous period.
Three Months Ended December 31, 2011 Compared to Three Months Ended December 31, 2010
Revenue from Pipeline Operations. Revenue from pipeline operations decreased by $382,549, or 79%, in the current quarter to $102,489 primarily due to the decrease in oil volumes transported. Revenue in the current quarter from the BDPS decreased to approximately $34,700 compared to approximately $397,500 in the previous quarter. Daily gas volumes transported on the BDPS averaged 1 MMcf of gas per day in the current quarter compared to 12 MMcf of gas per day in the previous quarter. Revenue on the GA 350 decreased to approximately $67,800 compared to approximately $87,500 in the previous quarter due to a decrease in average daily gas volumes transported of 13 MMcf of gas per day in the current quarter from 17 MMcf of gas per day in the previous quarter.
Revenue from Oil and Gas Sales. Revenue from oil and gas sales decreased by $245,945, or 42% to $338,570 in the current quarter primarily due to a reduction in production from the North Sumatra Basin-Langsa Field and High Island Block 115 in the same period.
Pipeline Operating Expenses. Pipeline operating expenses in the current quarter decreased by $233,193, or 96%, to $9,562 due to certain costs in the current quarter associated with the sale of the Buccaneer Pipeline and related assets to Sunoco that occurred in third quarter of 2011. Excluding this, pipeline operating expenses in the current quarter decreased $47,176, or 19%, due to decreases in pipeline repairs and maintenance costs, property taxes, saltwater disposal transportation costs and contract labor, which was offset by an increase in legal expenses.
Lease Operating Expenses. Lease operating expenses decreased in the current quarter by $66,203, or 15%, to $357,534 primarily as a result of decreased production from the North Sumatra Basin-Langsa Field.
Depletion, Depreciation and Amortization. Depletion, depreciation and amortization increased by $29,513, or 19%, in the current quarter to $185,036 primarily due to additional depletion on the domestic oil and gas properties.
General and Administrative Expenses and Stock Based Compensation. General and administrative expenses and stock based compensation expenses increased by $174,895, or 62%, to $458,161 in the current quarter primarily due to increases in shareholder reporting expenses, franchise tax, employee insurance, software maintenance fees and employee bonuses. The increases were partially offset by decreases in consulting expense.
Index to Financial Statements Impairment of Oil and Gas Properties. During the fourth quarter of the current period we recorded a full cost ceiling impairment of $252,706 on our U.S. Gulf of Mexico oil and gas properties.
Liquidity and Capital Resources
Sources and Uses of Cash. Our primary source of cash is cash flow from operations and cash on hand. During 2011, we had positive cash flow from operations of approximately $1,686,797 mainly due to the sale of the Buccaneer Pipeline and related assets to Sunoco for proceeds of approximately $3.6 million in cash.
The Nixon Facility will provide Blue Dolphin with positive cash flow. We expect to fund our operations, any additional capital expenditures related to the Nixon Facility and the potential acquisition of LED with the proceeds from the sale of refined products. Further, we expect our overall liquidity to increase in 2012 due to the revenue generated by the Nixon Facility.
We do not enter into any hedges or any type of derivatives to offset changes in commodity prices. We also do not have any outstanding debt or a credit facility with a bank or institution that may restrict us from issuing debt or Common Stock. At December 31, 2011, our current available cash was $1,941,221.
In recent years, we have used a portion of our cash reserves to fund our working capital requirements that were not funded from operations.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules at or before their adoption, and believe the proper implementation and consistent application of accounting rules is critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by comparatively analyzing similar situations and reviewing the accounting guidance governing them, and may consult with our independent registered independent accounting firm about the appropriate interpretation and application of these policies. Our most critical accounting policies currently relate to the accounting for the impairment of long-lived assets, which include primarily our oil and gas properties and our pipeline assets, as of December 31, 2011 and the accounting for future asset retirement costs.
Index to Financial Statements Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with the provisions of the Accounting Standards Codification (“ASC”) on accounting for the impairment or disposal of long-lived assets, we initiate a review for impairment of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. Recoverability of an asset is measured by comparison of its carrying amount to the expected future undiscounted cash flows expected to result from the use and eventual disposition of that asset, excluding future interest costs that would be recognized as an expense when incurred. Any impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its fair market value. Significant management judgment is required in the forecasting of future operating results which are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. Currently, our pipeline assets are significantly underutilized and such underutilization is an indicator of possible impairment at December 31, 2011. Accordingly, in reviewing our expected future cash flows as of December 31, 2011, we expect to be generated positive cash flow from our pipeline assets based on certain assumptions. The most significant assumption made in connection with the preparation of expected future cash flows is that pipeline throughput volumes will increase over the next few years due to increased leasing and drilling activities surrounding our pipelines from current and prospective oil and gas companies. Based on the results of the impairment test, which indicates expected future undiscounted cash flows are in excess of the pipeline assets net carrying value, no impairment was recorded at December 31, 2011.
Asset Retirement Obligations. The accounting for future abandonment costs changed in August 2001, with the adoption of guidance on accounting for asset retirement obligations. This guidance requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Future asset retirement costs include costs to dismantle, relocate or dispose of our offshore platforms, pipeline systems and related onshore facilities, plugging and abandonment of wells and land and sea bed restoration costs. We develop these cost estimates for each of our assets based upon regulatory requirements, platform structure, water depth, reservoir characteristics, reservoir depth, equipment market demand, current procedures and construction and engineering consultations. Because these costs typically extend many years into the future, estimating these future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on a quarterly basis.
Accounting for Uncertainty in Income Taxes. The current guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. It also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
The evaluation of a tax position in accordance with the guidance is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of the guidance are to be applied to all tax positions. Only tax positions that meet the more-likely-than-not recognition threshold are recognized.
Index to Financial Statements The provisions of the guidance have been applied to all of our material tax positions taken through the fiscal year ended December 31, 2011. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold prescribed by the guidance. In addition, we determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the pronouncement.
Fair Value Measurements. We follow guidance on fair value measurements, which clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
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Index to Financial Statements
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements:
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Index to Financial Statements Report of Independent Registered Public Accounting Firm
The Board of Directors and
Stockholders of Blue Dolphin Energy Company
Houston, Texas
We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and Subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s 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 audits 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 audits 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 consolidated financial position of the Company as of December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
/s/ UHY LLP
Houston, Texas
March 30, 2012
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholders’ Equity
See accompanying notes to consolidated financial statements.
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Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
NOTES TO CONDOLIDATED FINANCIALSTATEMENTS
(1) Organization and Significant Accounting Policies
Organization
Blue Dolphin Energy Company (“Blue Dolphin,” “we” and “our”) was incorporated in Delaware in January 1986 to engage in oil and gas exploration, production and acquisition activities and oil and gas transportation and marketing services. We were formed pursuant to a reorganization effective June 9, 1986.
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Reverse Stock Split
On June 9, 2010 our stockholders approved a reverse stock split of our common stock, par value $0.01 per share (the “Common Stock”) at a ratio within a range from 1 for 5 (1:5) to 1 for 10 (1:10), at the discretion of the Board, at any time prior to September 1, 2010. The Board set the reverse stock split ratio at 1 for 7 (1:7) on June 30, 2010. The effective date for the reverse stock split was July 16, 2010. No fractional shares were issued in connection with the reverse stock split. Each holder of Common Stock who would otherwise be entitled to receive a fractional share of Common Stock was, in lieu of such fractional share, paid in cash at fair market value. We paid approximately $2,604 for the repurchase of fractional shares.
In addition, the Board elected not to alter the number of authorized shares or change the par value of the Common Stock, such number of authorized shares remaining at 100,000,000 shares and such par value remaining a $0.01 per share. Earnings per share, common stock outstanding and weighted average common stock outstanding as referred to in these consolidated financial statements have been restated, where applicable, to give retroactive effect of the reverse stock split.
Accounting Estimates
We have made a number of estimates and assumptions relating to the reporting of consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) as codified by the Financial Accounting Standards Board (“FASB”) in its Accounting Standards Codification (“ASC”), pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). This includes assessing the realization of the note receivable, the estimated useful life of pipeline assets, valuation of stock-based payments and reserve information, which affects the depletion calculation as well as the full cost ceiling limitation. While we believe current estimates are reasonable and appropriate, actual results could differ from those estimated.
Cash and Cash Equivalents
Cash equivalents include liquid investments with an original maturity of three months or less. We maintain cash and cash equivalent balances at one financial institution that is insured by the Federal Deposit Insurance Corporation (the “FDIC”). Cash balances are maintained in depository and overnight investment accounts with financial institutions which at times, exceed insured limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
In October 2008, the FDIC amended its deposit insurance provisions to increase the basic limit amount from $100,000 to $250,000 per depositor. The coverage increase, which was intended to be temporary, was to revert back to $100,000 per depositor limit on December 31, 2009. However, in May 2009, the FDIC extended the coverage date through December 31, 2013. The temporary increase was made permanent in 2010 by the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Oil and Gas Properties
Oil and gas properties are accounted for 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. We use one cost center for our U.S. Gulf of Mexico properties and one cost center for our Indonesian properties. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or impairment has occurred.
Estimated proved oil and gas reserves are based upon reports prepared by third-party petroleum engineering consulting firms. The net carrying value of oil and gas properties, less related deferred income taxes, is limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% discount rate applied) of estimated future net revenue from proved reserves, after giving effect to income taxes, and the lower of cost or estimated fair value of unproved properties. Since our unamortized cost exceeded the present value of estimated future net revenue from domestic operations, we recorded an impairment to our U.S. Gulf of Mexico oil and gas properties of $252,706 in 2011. We recorded no such impairment in 2010. Disposition of oil and gas properties is recorded as adjustments to capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.
We capitalize interest on expenditures made in connection with significant exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest has been capitalized for the years reflected herein.
Pipelines and Facilities
Pipelines and facilities 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 the ASC 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. We did not have any impairment of our pipelines and facilities for the years ended December 31, 2011 and 2010. During the year, BDPL sold its eighty-three and one-third percent (83 1/3%) undivided interest in the Buccaneer Pipeline to Sunoco Partners Marketing and Terminals L.P. (“Sunoco”). BDPL still maintains its 83 1/3% undivided interest in the Galveston Area Block 350 Pipeline, as well as an 83 1/3% undivided interest in the Omega Pipeline.
Other Property and Equipment
Depreciation of furniture, fixtures and other equipment is computed using the straight-line method over estimated useful lives ranging from 3 to 10 years.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Asset Retirement Obligations
We follow the guidance on accounting for asset retirement obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.
The guidance requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. If the obligation is settled for other than the carrying amount of the liability, a gain or loss on settlement is recognized.
We have asset retirement obligations associated with the future abandonment of our pipelines and related facilities and our offshore oil and gas properties. The following table summarizes our asset retirement obligation transactions during the years ended December 31, 2011 and 2010.
Stock-Based Compensation
Stock-based compensation is recognized in our consolidated financial statements based on the fair value, on the date of grant or modification, of the equity instrument awarded. Stock-based compensation expense is recognized in the consolidated financial statements on a straight-line basis over the requisite service period for the entire award.
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, 2011 was not material.
Recognition of Pipeline Transportation Revenue
Revenue from our pipelines is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Allowance for Doubtful Accounts
Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due 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 aged accounts receivables for collectability and establish an allowance as necessary for individual customer balances. As of December 31, 2011 and 2010, we did not record an allowance for doubtful accounts.
Income Taxes
We provide for income taxes using the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
The evaluation of a tax position is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
Earnings Per Share
We apply the provisions of the ASC for computing earnings per share. The guidance requires the presentation of basic earnings per share (“EPS”) which excludes dilution and is computed by dividing net income (loss) available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of the consolidated statement of operations and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income (loss) available to common shareholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue common stock were converted to common stock that then shared in the earnings of the entity.
Employee stock options and stock warrants outstanding were not included in the computation of diluted earnings per share for the year ended December 31, 2010, because their assumed exercise and conversion would have an anti-dilutive effect on the computation of diluted income (loss) per share.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
The following table provides reconciliation between basic and diluted income (loss) per share:
Environmental
We are subject to extensive domestic and foreign environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amounts and timing of payments is fixed or reliably determinable. As of December 31, 2011 and 2010, no environmental violation was recorded on our consolidated balance sheets.
(2) Fair Value of Financial Instruments
The carrying values of cash and cash equivalents, accounts receivable and accounts payable, accrued liabilities and other current liabilities approximate fair value due to the short-term maturities of these instruments.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(3) Loan Receivable
We recorded an allowance for doubtful loan receivable of $1.5 million at December 31, 2009. The loan receivable is associated with a $2.0 million loan, net of credited and recovered amounts (the “Loan”), made to Lazarus Louisiana Refinery II, LLC (“LLRII”) on July 31, 2009 and due on January 31, 2010. At December 31, 2011 and 2010, we maintained an allowance for the uncollected balance of the Loan.
Pursuant to a Settlement Agreement and Mutual Release dated February 15, 2012, by and among Blue Dolphin, Lazarus Energy Holdings, LLC (“LEH”) and LLRII, the parties agreed to settle and compromise all disputes between them in connection with closing of the Acquisition in the subsequent period. LEH has 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 has 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.
(4) Income Taxes
Income tax expense consisted of $20,921 and $4,585 and was related to state income tax for the years ended 2011 and 2010, respectively.
The income tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010 are presented below:
In assessing the recoverability of deferred tax assets, we determine whether it is more likely than not that some portion or all of the deferred tax assets will be realized. A full valuation allowance against our deferred tax asset was recognized at December 31, 2011 and 2010 due to our uncertainty as to the utilization of the deferred tax assets in the foreseeable future. The net change in the total valuation allowance for the year ended December 31, 2011 was a decrease of $412,700 in 2011 and an increase $329,864 in 2010.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Our effective tax rate applicable to continuing operations in 2011 and 2010 is as follows:
For federal tax purposes, we had net operating loss carry-forwards (“NOLs”) of approximately $19.7 million at December 31, 2011. These NOLs must be used prior to their expiration, which will occur between 2018 and 2030.
We adopted the provisions of the ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.
The provisions of the guidance on accounting for uncertainty in income taxes have been applied to all of our material tax positions taken for all open tax years on the date of adoption through the fiscal year ended December 31, 2011. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold. In addition, we have determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the guidance.
The State of Texas has a business tax that is imposed on gross revenue to replace its prior franchise tax regime. Although the Texas margins tax (“TMT”) is imposed on an entity’s gross revenue rather than on its net income, certain aspects of the tax make it similar to an income tax. In accordance with the accounting guidance, we have properly determined the impact of the TMT in the determination of our reported state current and deferred income tax liability.
As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax expense. However, there were no amounts recognized relating to interest and penalties in the consolidated statements of operations for the years ended December 31, 2011 and 2010. Furthermore, none of our federal and state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. As of December 31, 2011, fiscal years 2008 and later remain subject to examination by the IRS and fiscal years 2007 and later remain subject to examination by State of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.
(5) Stock Options
We adopted the 2000 Stock Incentive Plan (the “2000 Plan”) effective April 14, 2000, under which we make stock-based compensation awards. In 2007, the number of shares of common stock, par value $0.01 per share (the “Common Stock”), reserved for grants of incentive stock options (“ISOs”) and other stock-based awards under the 2000 Plan was increased to 1,200,000 shares. In July 2010, our stockholders approved a 1-for-7 reverse-stock-split of our Common Stock, which reduced the number of shares available for grant under the 2000 Plan from 1,200,000 shares to 171,128 shares. As of December 31, 2011, we had 80,495 shares of Common Stock available for future grants. Options granted under the 2000 Plan have contractual terms ranging
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
from six to ten years. The exercise price of ISOs cannot be less than 100% of the fair market value of a share of our Common Stock as determined on the grant date. With the exception of certain ISOs granted in 2007 and 2008, all ISO awards vested immediately. Specifically, 200,000 ISOs granted in May 2007 and 75,000 ISO’s granted in August 2008 have a three year vesting period and 150,000 ISOs granted in October 2007 have a two year vesting period. An additional 28,500 options were granted in October 2007 that vested immediately. Although the 2000 Plan provides for the granting of other incentive awards, only ISOs and non-statutory stock options have been issued under the 2000 Plan. The 2000 Plan is administered by the Compensation Committee of the Board.
Subsequent to the year ended December 31, 2011, our stockholders approved two amendments to the 2000 Plan: (i) resetting the expiration date from April 14, 2010 to April 14, 2020 and (ii) increasing the number of shares of Common Stock available for issuance from 171,128 shares to 1,000,000 shares.
We are permitted a corporate income tax deduction for certain stock options that are exercised by our employees. The corporate income tax deduction is the amount of income recognized by the employee as a result of exercising the stock option. The income tax benefit, when taken, is shown on our Consolidated Statement of Cash Flows as financing cash inflows. For the foreseeable future, any tax deductions we receive from the exercise of stock options will be applied to the valuation allowance in determining our net operating loss carry forward.
Additionally, we used the alternate transition method (simplified method) for calculating the beginning balance in the pool of excess tax benefits in accordance with ASC’s guidance on transition election related to accounting for the tax effects of share-based payment awards.
We estimate the fair value of stock options granted on the date of grant using the Black-Scholes-Merton option-pricing model. There were no options granted during the years ended December 31, 2011 and 2010. Expected volatility when used in the model is based on the historical volatility of our Common Stock and is weighted 50% for the historical volatility over a past period equal to the expected term and 50% for the historical volatility over the previous two years prior to the grant date.
The expected term of options granted used in the model represents the period of time that options granted are expected to be outstanding. The method used to estimate the expected term is the “simplified” method as allowed under the provisions of SEC Staff Accounting Bulletin No. 107. This number is calculated by taking the average of the sum of the vesting period and the original contract term. The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of the grant. As we have not declared dividends on our Common Stock since we became a public entity, no dividend yield is used. No forfeiture rate is assumed due to the forfeiture history for this type of award. Actual value realized, if any, is dependent on the future performance of our Common Stock and overall stock market conditions. There is no assurance that the value realized by an optionee will be at or near the value estimated by the Black-Scholes-Merton option-pricing model.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
At December 31, 2011, there were a total of 28,887 shares of Common Stock reserved for issuance upon exercise of outstanding options under the 2000 Plan. A summary of the status of our stock options granted to key employees, officers and directors, for the purchase of shares of Common Stock, is as follows:
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Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
The following table summarizes additional information about stock options outstanding at December 31, 2011:
The following summarizes the net change in non-vested stock options for the years shown:
As of December 31, 2011, there was no unrecognized compensation cost related to non-vested stock options granted under the 2000 Plan.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
(6) Leases
We have various operating leases that extend through 2013. The following is a schedule of future minimum lease payments under non-cancelable operating leases exceeding one year at December 31, 2011:
Rent expense on operating leases for the years indicated are as follows:
(7) Commitments and Contingencies
We are involved in various claims and legal actions arising in the ordinary course of business. In our opinion, the ultimate disposition of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
(8) Business Segment Information
At December 31, 2011, our operations were conducted in two business segments: (i) pipeline transportation services and (ii) oil and gas exploration and production. These segments were managed jointly due to our size. We use earnings before interest expense and income taxes (“EBIT”) to assess the operating results and effectiveness of our business segments, which consist of our consolidated businesses and investments. We believe EBIT is useful to our investors because it allows them to evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) 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 (income). We exclude interest expense (income) and other expense 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 EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating cash flows.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Below is a reconciliation of our EBIT (by segment) for each of the years ended December 31, 2011 and 2010:
(1) Includes unallocated G&A costs associated with corporate maintenance costs and legal expenses. It also includes as identifiable assets corporate available cash of $0.1 million.
(2) Allocable G&A 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.
(1) Includes unallocated G&A costs associated with corporate maintenance costs and legal expenses. It also includes as identifiable assets corporate available cash of $0.6 million.
(2) Allocable G&A 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.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
We are exposed to concentrations of credit risk as 100% of our customers are within the oil and gas industry. Our customers may be similarly affected by changes in economic, regulatory or other factors. Trade receivables are generally not collateralized. However, our customers’ historical and future credit positions are thoroughly analyzed prior to extending credit. Revenue from customers exceeding 10% of our total revenue was as follows for the periods indicated:
(9) Disposition of Assets
Pursuant to an Asset Purchase Agreement, BDPL sold its eighty-three and one-third percent (83 1/3%) undivided interest in the Buccaneer Pipeline, as well as some related assets, to Sunoco for proceeds of approximately $3.6 million in cash. The transaction closed on August 3, 2011.
(10) Subsequent Events
Acquisition of LE. As previously reported, we entered into a Purchase and Sale Agreement (the “PSA”) with LEH and LEH’s wholly-owned subsidiaries to acquire one hundred percent (100%) of the issued and outstanding membership interests of LE. LE’s primary asset is the 56-acre Nixon Crude Oil Processing Facility (the “Nixon Facility”).
On February 15, 2012, we acquired LE and issued, in reliance on the exemption provided by Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), 8,393,560 shares of Common Stock, subject to anti-dilution adjustments, to LEH as consideration for LE (the “Original BDEC Shares”). Additionally, on February 21, 2012, pursuant to the anti-dilution provisions contained in the PSA, and in reliance on the exemption provided by Section 4(2) of the Securities Act, we issued 32,896 shares of Common Stock to LEH (the “Anti-Dilution Shares” and together with the Original BDEC Shares, the “BDEC Shares”) effective February 15th, 2012. As a result of our issuance of the BDEC Shares, LEH currently owns eighty percent (80%) of our issued and outstanding Common Stock. The issuance of the BDEC Shares to LEH resulted in a change in control of Blue Dolphin. Further, pursuant to the terms of the Purchase and Sale Agreement, the composition of the Board and management changed. See our Current Reports on Form 8-K filed with the Securities and Exchange Commission on July 22, 201, February 2, 2012, February 21, 2012, February 28, 2012 and March 14, 2012, for more information on the Acquisition.
Management of Blue Dolphin’s Assets. As part of LEH’s assignment of the membership interests of LE, on February 15, 2012, Blue Dolphin, LE and LEH entered into a Management Agreement (the “Management Agreement”) pursuant to which LEH agreed to manage and operate the Nixon Facility and Blue Dolphin’s other operations (collectively, the “Services”). Pursuant to the terms of the Management Agreement, LEH shall retain, as compensation for the Services, the right to receive (i) weekly payments based on revenues from the sale of diesel blend stocks processed by the Nixon Facility not to exceed $750,000 per month, (ii) reimbursement for certain accounting
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
costs related to the preparation of LE’s financial statements 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 processed at the Nixon Facility during the term of the Management Agreement, to the extent the quantity exceeds 10,000 barrels per day determined on a monthly basis. We further 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 a third party dated August 12, 2011, 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 may be terminated if the Board determines that the Management Agreement is no longer in the best interest of Blue Dolphin.
LEH owns approximately eighty percent (80%) of our issued and outstanding Common Stock. 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 Chief Financial Officer, 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. See “Part I, Item 1A. Risk Factors” of this report related to related party transactions.
Lazarus Energy Development, LLC (“LED”) Acquisition. Pursuant to the terms of the PSA, we had the option to acquire all of the issued and outstanding membership interests of LED, a Delaware limited liability company and a wholly-owned subsidiary of LEH. Among other assets, LED holds approximately 46 acres of real property adjacent to the Nixon Facility. On February 7, 2012, we paid LEH a refundable deposit of approximately $183,000 to exercise the option and as partial payment of the purchase price for LED. As part of the acquisition, we agreed to assume an LED loan in the amount of $1.5 million collateralized by the real property adjacent to the Nixon Facility. We expect to complete the acquisition of LED from LEH in the first half of 2012 for a total purchase price of approximately $1.68 million. See “Part I, Item 1A. Risk Factors” of this report related to acquisition opportunities, as well as “Liquidity and Capital Resources” under “Part II, Item 7” of this report for additional information on how we plan to fund the acquisition of LED.
(11) Supplemental Oil and Gas Information (Unaudited)
The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.
Associated with our non-operating interest in the North Sumatra Basin-Langsa Field, we recognized gas and oil sales revenue of approximately $1,222,400 and $720,300 in 2011 and 2010, respectively, and lease operating expenses of approximately $1,098,500 and $601,200 in 2011 and 2010, respectively. We have a working interest of 7.0% and a net revenue interest of 5.20625%, subject to reversion, in the oil field.
Associated with our non-operating interest in High Island Block 115, we recognized gas and oil sales revenue of approximately $84,200 and $48,900 in 2011 and 2010, respectively, and lease operating expenses of approximately $35,100 and $32,900 in 2011 and 2010, respectively. We have a working interest of 2.5% and a net revenue interest of 2.008% in one zone of a single well in the lease.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Associated with our non-operating interest in Galveston Area Block 321, we recognized gas and oil sales revenue of approximately $26,900 and $48,200 in 2011 and 2010, respectively. We did not incur lease operating expenses in 2011 and 2010. We have an overriding royalty interest of 0.5% in an exploratory well in the lease.
Associated with our non-operating interest in High Island Block 37, we recognized gas and oil sales revenue of approximately $9,200 and $45,300 in 2011 and 2010, respectively, and lease operating expenses of approximately $27,500 and $39,500 in 2011 and 2010, respectively. We have a working interest of 2.88% and a net revenue interest of 2.246% in the block.
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
We retained independent petroleum engineering consulting firms to provide year-end estimates of our future net recoverable oil and natural gas. Estimated proved net recoverable reserves as indicated herein include only those quantities that can be expected to be commercially recoverable. Estimated reserves for the year ended December 31, 2011 were computed using benchmark prices based on the unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas during each month of 2011, as required by SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting,” effective December 31, 2009. Costs were estimated using costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods.
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Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Set forth below is a summary of the changes in the estimated quantities of our crude oil and condensate, and gas reserves for the periods indicated, as estimated by us at December 31, 2011 and 2010. Our reserves are located in the North Sumatra Basin offshore Indonesia and U.S. Gulf of Mexico. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions.
Proved reserves are estimated quantities of gas, crude oil, and condensate that geological and engineering data demonstrate, with reasonable certainty, are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Capitalized Costs of Oil and Gas Producing Activities
The following table sets forth the aggregate amounts of capitalized costs relating to our oil and gas producing activities and the aggregate amount of related accumulated depletion, depreciation, amortization as of:
Costs Incurred in Oil and Gas Producing Activities
The following table reflects the costs incurred in oil and gas property acquisition, disposition, exploration and development activities during the periods indicated:
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Results of Operations for Oil and Gas Producing Activities
The results of operations from oil and gas producing activities below exclude non-oil and gas revenue, general and administrative expenses, interest expense and interest income.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The following table reflects the Standardized Measure of Discounted Future Net Cash Flows relating to our interest in proved oil and gas reserves for:
Future net cash flows at each year end, as reported in the above schedule, were determined by summing the estimated annual net cash flows computed by: (i) multiplying estimated quantities of proved reserves to be produced during each year by year-end prices and (ii) deducting estimated expenditures to be incurred during each year to develop and produce the proved reserves (based on year-end costs).
Index to Financial Statements BLUE DOLPHIN ENERGY COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements (Continued)
Income taxes were computed by applying year-end statutory rates to pretax net cash flows, reduced by the tax basis of the properties and available net operating loss carry-forwards. The annual future net cash flows were discounted, using a prescribed 10% rate, and summed to determine the standardized measure of discounted future net cash flow.
We caution readers that the standardized measure information which places a value on proved reserves is not indicative of either fair market value or present value of future cash flows. Other logical assumptions could have been used for this computation which would likely have resulted in significantly different amounts. Such information is disclosed solely in accordance with authoritative guidance and the requirements promulgated by the SEC to provide readers with a common base for use in preparing their own estimates of future cash flows and for comparing reserves among companies. We do not rely on these computations when making investment and operating decisions. Principal changes in the Standardized Measure of Discounted Future Net Cash Flows attributable to our proved oil and gas reserves for the periods indicated are as follows:
Index to Financial Statements
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the year covered by this report, we carried out an evaluation under the supervision and with the participation of our management, including our Principal Executive Officer and our Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon this evaluation, as of December 31, 2011, the Principal Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including the Principal Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-5(f) under the Exchange Act). Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control - Integrated Framework. Our management has concluded that, as of December 31, 2011, our internal control over financial reporting is effective based on these criteria. This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting pursuant to the permanent exemption for smaller reporting companies that permit us to provide only management’s report.
Our management, including our Principal Executive Officer and Principal Financial Officer, does not expect our internal control over financial reporting to prevent all error or fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must take into account resource constraints. The benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Our internal control over financial reporting, however, is designed to provide reasonable assurance that the objectives of internal control over financial reporting are met.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2011, there were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act), that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
Index to Financial Statements PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Item 10 is incorporated by reference to our definitive proxy statement relating to our 2012 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference to our definitive proxy statement relating to our 2012 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 is incorporated by reference to our definitive proxy statement relating to our 2012 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated by reference to our definitive proxy statement relating to our 2012 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 is incorporated by reference to our definitive proxy statement relating to our 2012 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
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Index to Financial Statements PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) List of documents filed as part of this report
3. Exhibits. We hereby file as part of this Annual Report on Form 10-K the Exhibits listed in the attached Exhibit Index.
Index to Financial Statements
* Management Compensation Plan.
** Filed herewith
(1) Incorporated herein by reference to Exhibit 3.1 filed in connection with the Form 8-K of Blue Dolphin under the Exchange Act dated June 2, 2009 (Commission File No. 000-15905).
(2) Incorporated herein by reference to Exhibit 3.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated December 26, 2007 (Commission File No. 000-15905).
(3) Incorporated herein by reference to exhibits filed in connection with Form 10-K of Blue Dolphin for the year ended December 31, 1989 under the Exchange Act dated March 30, 1990 (Commission File No. 000-15905).
(4) Incorporated herein by reference to Exhibit 10.4 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated September 14, 2004 (Commission File No. 000-15905).
Index to Financial Statements
(5) Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated August 6, 2009 (Commission File No. 000-15905).
(6) Incorporated herein by reference to Appendix 1 filed in connection with the Proxy Statement of Blue Dolphin under the Exchange Act dated April 20, 2000 (Commission File No. 000-15905).
(7) Incorporated herein by reference to Appendix B filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated April 16, 2003 (Commission File No. 000-15905).
(8) Incorporated herein by reference to Appendix A filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated April 27, 2006 (Commission File No. 000-15905).
(9) Incorporated herein by reference to Exhibit B filed in connection with the definitive Proxy Statement of Blue Dolphin under the Exchange Act dated December 28, 2011 (Commission File No. 000-15905).
(10) Incorporated herein by reference to Exhibit 10.20 filed in connection with Form 10-KSB of Blue Dolphin under the Exchange Act dated March 21, 2003 (Commission File No. 000-15905).
(11) Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated November 3, 2004 (Commission File No. 000-15905).
(12) Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated March 3, 2005 (Commission File No. 000-15905).
(13) Incorporated herein by reference to Exhibit 10.9 filed in connection with Form 10-KSB of Blue Dolphin for the year ended December 31, 2005 under the Exchange Act dated March 30, 2006 (Commission File No. 000-15905).
(14) Incorporated herein by reference to Exhibit 10.10 filed in connection with Form 10-KSB of Blue Dolphin for the year ended December 31, 2005 under the Exchange Act dated March 30, 2006 (Commission File No. 000-15905).
(15) Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated August 6, 2009 (Commission File No. 000-15905).
(16) Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 21, 2010 (Commission File No. 000-15905).
(17) Incorporated herein by reference to Exhibit 10.2 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 21, 2010 (Commission File No. 000-15905).
(18) Incorporated herein by reference to Exhibit 10.1 filed in connection with Form 8-K of Blue Dolphin under the Exchange Act dated July 22, 2011 (Commission File No. 000-15905).
(19) Incorporated herein by reference to Exhibit 10.2 filed in connection with Amendment No. 1 to Form 8-K of Blue Dolphin under the Exchange Act dated March 14, 2012 (Commission File No. 000-15905).
(20) Incorporated herein by reference to Exhibit 14.1 filed in connection with Form 10-KSB of Blue Dolphin for the year ended December 31, 2004 under the Exchange Act dated March 25, 2005 (Commission File No. 000-15905).
Index to Financial Statements SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BLUE DOLPHIN ENERGY COMPANY
(Registrant)
By:
/s/ JONATHAN P. CARROLL
Jonathan P. Carroll
Chief Executive Officer, President
Assistant Treasurer and Secretary
(Principal Executive Officer)
Date: March 30, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.