Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | 15-May-15 | |
Document And Entity Information | ||
Entity Registrant Name | BLUE DOLPHIN ENERGY CO | |
Entity Central Index Key | 793306 | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Amendment Flag | FALSE | |
Current Fiscal Year End Date | -19 | |
Is Entity a Well-known Seasoned Issuer? | No | |
Is Entity a Voluntary Filer? | No | |
Is Entity's Reporting Status Current? | Yes | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 10,449,444 | |
Document Fiscal Period Focus | Q1 | |
Document Fiscal Year Focus | 2015 |
Consolidated_Balance_Sheets_Un
Consolidated Balance Sheets (Unaudited) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $2,279,206 | $1,293,233 |
Restricted cash | 1,011,112 | 1,008,514 |
Accounts receivable | 9,876,395 | 8,340,303 |
Prepaid expenses and other current assets | 120,764 | 771,458 |
Deposits | 120,176 | 68,498 |
Inventory | 3,070,710 | 3,200,651 |
Deferred tax assets, current portion, net | 17,779 | |
Total current assets | 16,496,142 | 14,682,657 |
Total property and equipment, net | 38,263,759 | 37,371,075 |
Surety bonds | 1,642,000 | 1,642,000 |
Debt issue costs, net | 500,122 | 479,737 |
Trade name | 303,346 | 303,346 |
Deferred tax assets, net | 3,934,843 | 5,928,342 |
TOTAL ASSETS | 61,140,212 | 60,407,157 |
CURRENT LIABILITIES | ||
Accounts payable | 9,882,225 | 12,370,179 |
Accounts payable, related party | 119,645 | 1,174,168 |
Asset retirement obligations, current portion | 86,341 | 85,846 |
Accrued expenses and other current liabilities | 3,773,607 | 2,783,704 |
Interest payable, current portion | 47,310 | 56,039 |
Long-term debt, current portion | 1,263,057 | 1,245,476 |
Deferred tax liabilities, net | 168,236 | |
Total current liabilities | 15,172,185 | 17,883,648 |
LONG-TERM LIABILITIES | ||
Asset retirement obligations, net of current portion | 1,833,693 | 1,780,924 |
Deferred revenues and expenses | 648,305 | 691,525 |
Long-term debt, net of current portion | 10,491,117 | 10,808,803 |
Long-term interest payable, net of current portion | 1,326,080 | 1,274,789 |
Total long-term liabilities | 14,299,195 | 14,556,041 |
TOTAL LIABILITIES | 29,471,380 | 32,439,689 |
Commitments and contingencies (Note 20 | ||
STOCKHOLDERS' EQUITY | ||
Common stock ($0.01 par value, 20,000,000 shares authorized;10,599,444 shares issued at March 31, 2015 and December 31, 2014) | 105,995 | 105,995 |
Additional paid-in capital | 36,718,781 | 36,718,781 |
Accumulated deficit | -4,355,944 | -8,057,308 |
Treasury stock, 150,000 shares at cost | -800,000 | -800,000 |
Total stockholders' equity | 31,668,832 | 27,967,468 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $61,140,212 | $60,407,157 |
Consolidated_Balance_Sheets_Un1
Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
STOCKHOLDERS' EQUITY | ||
Common stock, par value | $0.01 | $0.01 |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares issued | 10,599,444 | 10,599,444 |
Treasury stock, shares | 150,000 | 150,000 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (Unaudited) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
REVENUE FROM OPERATIONS | ||
Refined product sales | $61,067,062 | $120,376,151 |
Tank rental revenue | 286,892 | 282,516 |
Pipeline operations | 38,395 | 54,031 |
Total revenue from operations | 61,392,349 | 120,712,698 |
COST OF OPERATIONS | ||
Cost of refined products sold | 49,387,449 | 110,415,607 |
Refinery operating expenses | 2,880,971 | 2,955,019 |
Joint Marketing Agreement profit share | 2,438,637 | |
Pipeline operating expenses | 46,596 | 27,729 |
Lease operating expenses | 7,316 | 7,176 |
General and administrative expenses | 345,884 | 369,484 |
Depletion, depreciation and amortization | 399,231 | 390,605 |
Accretion expense | 53,215 | 50,802 |
Total cost of operations | 55,559,299 | 114,216,422 |
Income from operations | 5,833,050 | 6,496,276 |
OTHER INCOME (EXPENSE) | ||
Easement, interest and other income | 66,007 | 154,220 |
Interest expense | -208,075 | -253,800 |
Total other income (expense) | -142,068 | -99,580 |
Income before income taxes | 5,690,982 | 6,396,696 |
Income tax expense | -1,989,618 | -202,423 |
Net income | $3,701,364 | $6,194,273 |
Income per common share | ||
Basic | $0.35 | $0.59 |
Diluted | $0.35 | $0.59 |
Weighted average number of common shares outstanding: | ||
Basic | 10,449,444 | 10,430,973 |
Diluted | 10,449,444 | 10,430,973 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Unaudited) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
OPERATING ACTIVITIES | ||
Net income | $3,701,364 | $6,194,273 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depletion, depreciation and amortization | 399,231 | 390,605 |
Unrealized gain on derivatives | 548,190 | 127,100 |
Deferred taxes | 1,807,484 | |
Amortization of debt issue costs | 8,450 | 8,450 |
Accretion expense | 53,215 | 50,802 |
Changes in operating assets and liabilities | ||
Restricted cash | -2,598 | -675,736 |
Accounts receivable | -1,536,092 | 3,738,092 |
Prepaid expenses and other current assets | 650,694 | 70,655 |
Deposits and other assets | -80,513 | -449,553 |
Inventory | 129,941 | 289,506 |
Accounts payable, accrued expenses and other liabilities | -2,046,849 | -4,506,163 |
Accounts payable, related party | -1,054,523 | -38,693 |
Net cash provided by operating activities | 2,577,994 | 5,199,338 |
INVESTING ACTIVITIES | ||
Capital expenditures | -1,291,915 | -59,178 |
Net cash used in investing activities | -1,291,915 | -59,178 |
FINANCING ACTIVITIES | ||
Payments on long-term debt | -300,106 | -5,267,116 |
Payments on notes payable | -11,884 | |
Net cash used in financing activities | -300,106 | -5,279,000 |
Net increase (decrease) in cash and cash equivalents | 985,973 | -138,840 |
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 1,293,233 | 434,717 |
CASH AND CASH EQUIVALENTS AT END OF PERIOD | 2,279,206 | 295,877 |
Non-cash operating activities | ||
Surety bond funded by seller of pipeline interest | 850,000 | |
Non-cash investing and financing activities: | ||
New asset retirement obligations | 300,980 | |
Interest paid | 165,513 | 902,176 |
Income taxes paid |
1_Organization
1. Organization | 3 Months Ended | |
Mar. 31, 2015 | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Organization | Nature of Operations | |
Blue Dolphin Energy Company (http://www.blue-dolphin-energy.com, referred to herein, with its predecessors and subsidiaries, as “Blue Dolphin,” “BDEC,” “we,” “us” and “our”) is primarily an independent refiner and marketer of petroleum products. Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Wilson County, Texas (the “Nixon Facility”). As part of our refinery business segment, we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties, which are considered non-core to our business. See “Note (4) Business Segment Information” of this report for further discussion of our business segments. | ||
Structure and Management | ||
We were formed as a Delaware corporation in 1986. We are controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). Jonathan P. Carroll, Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. LEH also manages and operates our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business pursuant to an Operating Agreement (the “Operating Agreement”). | ||
Our operations are conducted directly and indirectly through our primary operating subsidiaries, as follows: | ||
● | Lazarus Energy, LLC, a Delaware limited liability company (petroleum processing assets) (“LE”); | |
● | Lazarus Refining & Marketing, LLC, a Delaware limited liability company (petroleum storage and terminaling) (“LRM”); | |
● | Blue Dolphin Pipe Line Company, a Delaware corporation (pipeline operations) (“BDPL”); | |
● | Blue Dolphin Petroleum Company, a Delaware corporation (exploration and production activities); and | |
● | Blue Dolphin Services Co., a Texas corporation (administrative services). |
2_Basis_of_Presentation
2. Basis of Presentation | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of operations, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations. |
3_Significant_Accounting_Polic
3. Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and notes are representations of management who is responsible for its integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements. |
Use of Estimates | |
We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated. | |
Cash and Cash Equivalents | |
Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $2,279,206 and $1,293,233 at March 31, 2015 and December 31, 2014, respectively. | |
Restricted Cash | |
Restricted cash represents a payment reserve account held by American First National Bank as security for payments under a 2008 loan agreement (the “Refinery Note”). Restricted cash was $1,011,112 and $1,008,514 at March 31, 2015 and December 31, 2014, respectively. | |
Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk | |
Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. | |
Concentration of Risk | |
Bank Accounts | |
Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $2,263,113 and $1,113,977 at March 31, 2015 and December 31, 2014, respectively. | |
Significant Customers | |
Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (14) Concentration of Risk” of this report for additional disclosures related to significant customers. | |
Inventory | |
The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products. Inventory reflected for crude oil and condensate is nominal and represents line fill. Because refined petroleum products are commodities, we have no control over the changing market value of these inventories. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated impairment expense. See “Note (7) Inventory” of this report for additional disclosures related to our inventory. | |
Derivatives | |
We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash. | |
Although these commodity futures contracts are not subject to hedge accounting treatment under FASB ASC guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statement of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting. | |
See “Note (18) Fair Value Measurement” and “Note (19) Refined Petroleum Products Inventory Risk Management” of this report for additional disclosures related to derivatives. | |
Property and Equipment | |
Refinery and Facilities | |
Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included as operating expenses under the Operating Agreement (see “Note (9) Accounts Payable Related Party” of this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances. | |
Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations. For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2015 and 2014. | |
Oil and Gas Properties | |
We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three months ended March 31, 2015 and 2014. All leases associated with our oil and gas properties have expired. | |
Pipelines and Facilities | |
We record pipelines and facilities at the lower of cost or net realizable value. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom. | |
Construction in Progress | |
Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service. | |
See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress. | |
Intangibles – Other | |
We have an acquisition-related intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014. | |
Debt Issue Costs | |
We have debt issue costs related to certain facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations. Debt issue costs, net of accumulated amortization, totaled $500,122 and $479,737 at March 31, 2015 and December 31, 2014, respectively. Accumulated amortization was $219,693 and $211,244 at March 31, 2015 and December 31, 2014, respectively. Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2015 and 2014. See “Note (12) Long-Term Debt” of this report for additional disclosures related to the Refinery Note. | |
Revenue Recognition | |
Refined Petroleum Products Revenue | |
We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil (“AGO”). Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. | |
Customers assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. | |
Tank Rental Revenue | |
Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. | |
Easement Revenue | |
Land easement revenue is recognized monthly as earned and is included in other income. | |
Pipeline Transportation Revenue | |
Revenue from our pipeline operations 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. | |
Deferred Revenue | |
On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”), and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”) whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for BDPL’s benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure. | |
Income Taxes | |
We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. | |
As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. | |
The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. | |
See “Note (16) Income Taxes” of this report for further information related to income taxes. | |
Impairment or Disposal of Long-Lived Assets | |
In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we initiate a review of our long-lived assets for impairment 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 comparing 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 that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. | |
Asset Retirement Obligations | |
FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. | |
Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. | |
We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating or disposing of our offshore platform, pipeline systems and related onshore facilities, as well as plugging and abandonment of wells and land and sea bed restoration costs. We developed 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 future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. | |
See “Note (11) Asset Retirement Obligations” of this report for additional information related to our AROs. | |
Computation of Earnings Per Share | |
We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income 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 our audited consolidated statements 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 available to common stockholders 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 shares of common stock were converted to common stock that then shared in the earnings of the entity. | |
The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock and similar instruments is dependent on this average stock price and will increase as the average stock price increases. See “Note (17) Earnings Per Share” for additional information related to EPS. | |
Stock-Based Compensation | |
In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period). | |
Treasury Stock | |
We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (13) Treasury Stock” for additional disclosures related to treasury stock. | |
Reclassification | |
We have reclassified certain insignificant prior period amounts related to our tank rental revenue to conform to our 2015 presentation. | |
New Pronouncements Issued but Not Yet Effective | |
In May 2014, FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. ASU 2014-09 is currently effective for reporting periods beginning after December 15, 2016, and early adoption is not permitted. | |
On April 1, 2015, FASB voted to propose a delay in the effective date of ASU 2014-09. As proposed, the new effective date would be annual reporting periods beginning after December 15, 2017, and the interim periods within that year. As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods. This proposal represents a one-year deferral from the original effective date. The proposed new effective date guidance would allow early adoption for all entities as of the original effective date (December 15, 2016). We are evaluating the impact that adoption of this guidance will have on the determination or reporting of our financial results. | |
In April 2015, FASB issued ASU 2015-03, Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. The amendments in this ASU are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets. |
4_Business_Segment_Information
4. Business Segment Information | 3 Months Ended | ||||||||||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||
Business Segment Information | We have two reportable business segments: (i) “Refinery Operations” and (ii) “Pipeline Transportation.” Business activities related to our “Refinery Operations” business segment are conducted at the Nixon Facility. Business activities related to our “Pipeline Transportation” business segment are primarily conducted in the Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties. Our “Pipeline Transportation” business segment is considered non-core to our business. | ||||||||||||||||||||||||||||||||
Business segment information for the three months ended March 31, 2015 and 2014 (and at March 31, 2015 and 2014), was as follows: | |||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2015 | Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||||||
Segment | Segment | ||||||||||||||||||||||||||||||||
Refinery | Pipeline | Corporate & | Refinery | Pipeline | Corporate & | ||||||||||||||||||||||||||||
Operations | Transportation | Other | Total | Operations | Transportation | Other | Total | ||||||||||||||||||||||||||
Revenue from operations | $ | 61,353,954 | $ | 38,395 | $ | - | $ | 61,392,349 | $ | 120,658,667 | $ | 54,031 | $ | - | $ | 120,712,698 | |||||||||||||||||
Less: cost of operations(1) | (52,259,470 | ) | (53,912 | ) | (408,048 | ) | (52,721,430 | ) | (113,368,578 | ) | (122,510 | ) | (334,729 | ) | (113,825,817 | ) | |||||||||||||||||
Other non-interest income | - | 62,500 | - | 62,500 | - | 125,000 | - | 125,000 | |||||||||||||||||||||||||
Adjusted EBITDA | 9,094,484 | 46,983 | (408,048 | ) | 8,733,419 | 7,290,089 | 56,521 | (334,729 | ) | 7,011,881 | |||||||||||||||||||||||
Less: JMA Profit Share(2) | (2,438,637 | ) | - | - | (2,438,637 | ) | - | - | - | - | |||||||||||||||||||||||
EBITDA | $ | 6,655,847 | $ | 46,983 | $ | (408,048 | ) | $ | 7,290,089 | $ | 56,521 | $ | (334,729 | ) | |||||||||||||||||||
Depletion, depreciation and amortization | (399,231 | ) | (390,605 | ) | |||||||||||||||||||||||||||||
Interest expense, net | (204,569 | ) | (224,580 | ) | |||||||||||||||||||||||||||||
Income before income taxes | $ | 5,690,982 | $ | 6,396,696 | |||||||||||||||||||||||||||||
Capital expenditures | $ | 1,291,915 | $ | - | $ | - | $ | 1,291,915 | $ | 59,178 | $ | - | $ | - | $ | 59,178 | |||||||||||||||||
Identifiable assets(3) | $ | 53,861,592 | $ | 2,923,368 | $ | 4,355,252 | $ | 61,140,212 | $ | 50,797,212 | $ | 3,201,220 | $ | 530,368 | $ | 54,528,800 | |||||||||||||||||
(1) | Operation cost within the “Refinery Operations” and “Pipeline Transportation” segments includes related general, administrative, and accretion expenses. Operation cost within “Corporate and Other” includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense. | ||||||||||||||||||||||||||||||||
(2) | The Joint Marketing Agreement profit share (the “JMA Profit Share”) represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Part 1, Item 1 - Note (20) Commitments and Contingencies” and “Part 1, Item 2. Management’s Discussion and Analysis and Results of Operations – Relationship with Genesis” of this report for further discussion of the Joint Marketing Agreement. | ||||||||||||||||||||||||||||||||
-3 | Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets. |
5_Prepaid_Expenses_and_Other_C
5. Prepaid Expenses and Other Current Assets | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||||||||
Prepaid Expenses and Other Current Assets | Prepaid expenses and other current assets consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Prepaid insurance | $ | 109,514 | $ | 156,558 | |||||
Prepaid listing fees | 11,250 | 15,000 | |||||||
Prepaid professional fees | - | 104,000 | |||||||
Unrealized hedging gains | - | 495,900 | |||||||
$ | 120,764 | $ | 771,458 |
6_Deposits
6. Deposits | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Banking and Thrift [Abstract] | |||||||||
Deposits | Deposits consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Equipment deposits | $ | 100,463 | $ | 48,785 | |||||
Utility deposits | 10,250 | 10,250 | |||||||
Rent deposits | 9,463 | 9,463 | |||||||
$ | 120,176 | $ | 68,498 |
7_Inventory
7. Inventory | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Inventory Disclosure [Abstract] | |||||||||
Inventory | Inventory consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Jet fuel | $ | 1,859,729 | $ | 2,631,546 | |||||
Naphtha | 476,767 | 194,688 | |||||||
AGO | 453,098 | 224,007 | |||||||
HOBM | 252,657 | 124,176 | |||||||
Crude | 19,041 | 19,041 | |||||||
LPG mix | 9,418 | 7,193 | |||||||
$ | 3,070,710 | $ | 3,200,651 |
8_Property_Plant_and_Equipment
8. Property, Plant and Equipment, Net | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Property, Plant and Equipment [Abstract] | |||||||||
Property, Plant and Equipment, Net | Property, plant and equipment, net, consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Refinery and facilities | $ | 36,547,078 | $ | 36,462,451 | |||||
Pipelines and facilities | 2,127,207 | 2,127,207 | |||||||
Onshore separation and handling facilities | 325,435 | 325,435 | |||||||
Land | 602,938 | 602,938 | |||||||
Other property and equipment | 627,479 | 597,064 | |||||||
40,230,137 | 40,115,095 | ||||||||
Less: Accumulated depletion, depreciation and amortization | (4,985,806 | ) | (4,586,575 | ) | |||||
35,244,331 | 35,528,520 | ||||||||
Construction in progress | 3,019,428 | 1,842,555 | |||||||
$ | 38,263,759 | $ | 37,371,075 |
9_Accounts_Payable_Related_Par
9. Accounts Payable, Related Party | 3 Months Ended |
Mar. 31, 2015 | |
Payables and Accruals [Abstract] | |
Accounts Payable, Related Party | LEH, our controlling shareholder, owns approximately 81% of Common Stock. Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH. LEH manages and operates all of our subsidiaries and all of our assets, including the Nixon Facility, (the “Services”) pursuant to the Operating Agreement. |
With respect to the Nixon Facility, the Operating Agreement covers all refinery operating expenses with the exception of capital expenditures. Pursuant to the Operating Agreement, for management and operation of the Nixon Facility LEH receives as compensation: (i) weekly payments from GEL TEX Marketing, LLC (“GEL”) not to exceed $750,000 per month, (ii) reimbursement for certain accounting costs related to the preparation of financial statements of LE not to exceed $50,000 per month, (iii) $0.25 for each barrel processed at the Nixon Facility during the term of the Operating 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 in excess of 10,000 barrels per day during the term of the Operating Agreement, determined on a monthly basis. For all other assets, LEH is reimbursed at cost for all reasonable expenses incurred while performing the Services. All compensation owed to LEH under the Operating Agreement is to be paid at the end of each calendar month. | |
Aggregate amounts expensed for Services at the Nixon Facility for the three months ended March 31, 2015 and 2014 were $2,880,971 (approximately $2.71 per barrel of throughput) and $2,955,019 (approximately $2.71 per barrel of throughput), respectively. | |
The amounts outstanding to LEH to fund our working capital requirements were $119,645 and $1,174,168 at March 31, 2015 and December 31, 2014, respectively, and are reflected in accounts payable, related party in our consolidated balance sheets. | |
The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 12, 2015, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party. |
10_Accrued_Expenses_and_Other_
10. Accrued Expenses and Other Current Liabilities | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Payables and Accruals [Abstract] | |||||||||
Accrued Expenses and Other Current Liabilities | Accrued expenses and other current liabilities consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Excise and income taxes payable | $ | 1,384,689 | $ | 1,228,411 | |||||
Genesis JMA Profit Share payable | 1,149,605 | 521,739 | |||||||
Transportation and inspection | 430,000 | 190,000 | |||||||
Board of director fees payable | 368,750 | 345,000 | |||||||
Unearned revenue | 220,631 | 252,500 | |||||||
Other payable | 103,580 | 149,962 | |||||||
Insurance | 64,062 | 96,092 | |||||||
Unrealized hedging loss | 52,290 | - | |||||||
$ | 3,773,607 | $ | 2,783,704 |
11_Asset_Retirement_Obligation
11. Asset Retirement Obligations | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset Retirement Obligations | Refinery and Facilities | ||||||||
Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Management believes that the refinery and facilities have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. | |||||||||
Pipelines and Facilities and Oil and Gas Properties | |||||||||
We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities, as well as the plugging and abandonment of our oil and gas properties. We recorded a discounted liability for the fair value an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. | |||||||||
For the three months ended March 31, 2015 and 2014, we did not incur any abandonment expense related to our oil and gas properties. Plugging and abandonment costs for oil and gas properties and pipelines are recorded as information becomes available from operators to substantiate actual and/or probable costs. | |||||||||
AROs on a roll-forward basis were as follows: | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Asset retirement obligations, at the beginning of the period | $ | 1,866,770 | $ | 1,597,661 | |||||
New asset retirement obligations and adjustments | 49 | 300,980 | |||||||
Liabilities settled | - | (243,866 | ) | ||||||
Accretion expense | 53,215 | 211,995 | |||||||
1,920,034 | 1,866,770 | ||||||||
Less: current portion of asset retirement obligations | (86,341 | ) | (85,846 | ) | |||||
Long-term asset retirement obligations, at the end of the period | $ | 1,833,693 | $ | 1,780,924 | |||||
The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of certain of the Pipeline Assets. For additional information related to the WBI Transaction, see “Note (3) Significant Accounting Policies – Revenue Recognition – Deferred Revenue” and “Note (20) Commitments and Contingencies – Supplemental Pipeline Bonds” of this report. |
12_LongTerm_Debt
12. Long-Term Debt | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Long-Term Debt | Long-term debt consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Refinery Note | $ | 8,545,466 | $ | 8,648,980 | |||||
Sovereign Loan | 1,479,949 | 1,638,898 | |||||||
Notre Dame Debt | 1,300,000 | 1,300,000 | |||||||
Capital Leases | 428,759 | 466,401 | |||||||
11,754,174 | 12,054,279 | ||||||||
Less: current portion of long-term debt | (1,263,057 | ) | (1,245,476 | ) | |||||
$ | 10,491,117 | $ | 10,808,803 | ||||||
Refinery Note | |||||||||
The Refinery Note accrues interest at a rate of U.S. Prime Rate plus 2.25% (effective rate of 5.50% at March 31, 2015) and has a maturity date of October 1, 2028 (the “Maturity Date”). LE’s obligations under the Refinery Note are secured by a Deed of Trust (“Deed of Trust”) of even date with the Refinery Note. The Refinery Note is further secured by a Security Agreement (the “Security Agreement” and, together with the Refinery Note and Deed of Trust, the “Refinery Loan Documents”) also of even date with the Refinery Note, which Security Agreement covers various items of collateral including a first lien on the Nixon Facility and general assets of LE. The principal balance outstanding on the Refinery Note was $8,545,466 and $8,648,980 at March 31, 2015 and December 31, 2014, respectively. Interest was accrued on the Refinery Note in the amount of $35,997 and $47,569 at March 31, 2015 and December 31, 2014, respectively. | |||||||||
The Refinery Note has debt-to-worth and current ratio financial maintenance covenants (the “Financial Maintenance Covenants”). As of March 31, 2015 and the date of filing this report, we were in compliance with the Financial Maintenance Covenants in the Refinery Note. As of March 31, 2014, we were in violation of the current ratio covenant in the Refinery Note. However, AFNB agreed to waive certain of the Financial Maintenance Covenants under the Refinery Note in a letter agreement effective December 31, 2013. | |||||||||
On September 1, 2013, AFNB and LE amended the Refinery Note (the “Note Modification Agreement”). Pursuant to the Note Modification Agreement, the monthly principal and interest payment due under the Refinery Note is $75,310. Other than modification of the payment terms under the Refinery Note, the terms of the Refinery Note remain the same through the Maturity Date and the Refinery Loan Documents remain in full force and effect. | |||||||||
Sovereign Loan | |||||||||
LRM entered into a loan and security agreement with Sovereign Bank, a Texas state bank (“Sovereign”), on May 2, 2014, for a term loan facility in the principal amount of $2.0 million (the “Sovereign Loan”). The proceeds of the Sovereign Loan are being used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. The Sovereign Loan is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio, (ii) secured by the assignment of certain leases of LRM, certain assets of LEH, our controlling shareholder and an affiliated entity, and (iii) guaranteed by Jonathan P. Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin and majority owner of LEH and an affiliated entity. The principal balance outstanding on the Sovereign Loan was $1,479,949 and $1,638,898 at March 31, 2015 and December 31, 2014, respectively. Interest was accrued on the Sovereign Loan in the amount of $7,649 and $8,470 at March 31, 2015 and December 31, 2014, respectively. | |||||||||
On March 25, 2015, Sovereign and LRM amended the Sovereign Loan pursuant to a Loan Modification Agreement (the “Loan Modification Agreement”). Under the Loan Modification Agreement, the interest rate on the Sovereign Loan was modified to be the greater of the U.S. Prime Rate plus 2.75% or 6.00%. In addition, the maturity date of the Sovereign Loan was extended to March 25, 2017. Pursuant to the Loan Modification Agreement, the monthly payment due under the Sovereign Loan is $61,665 plus interest. | |||||||||
Notre Dame Debt | |||||||||
LE entered into a loan with Notre Dame Investors, Inc. as evidenced by that certain promissory note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt accrues interest at a rate of 16.00% and is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at March 31, 2015 and December 31, 2014. Interest was accrued on the Notre Dame Debt in the amount of $1,326,080 and $1,274,789 at March 31, 2015 and December 31, 2014, respectively. There are no financial maintenance covenants associated with the Notre Dame Debt. The maturity date of the Notre Dame Debt is July 1, 2016. | |||||||||
Pursuant to Intercreditor and Subordination Agreements dated September 29, 2008 and August 12, 2011, the holder of the Notre Dame Debt and Subordinated Deed of Trust agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE in favor of the holder of the Refinery Note, the Deed of Trust and Security Agreement and Milam Services, Inc. (“Milam”), an affiliate of Genesis, under the Construction and Funding Agreement, respectively. | |||||||||
Capital Leases | |||||||||
Long-term capital lease obligations totaled $428,759 and $466,401 at March 31, 2015 and December 31, 2014, respectively. The following is a summary of equipment held under long-term capital leases: | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Cost | $ | 538,598 | $ | 538,598 | |||||
Less: accumulated depreciation | - | - | |||||||
$ | 538,598 | $ | 538,598 | ||||||
On August 7, 2014, we entered into a 36 month “build-to-suit” capital lease for the purchase of new boiler equipment for the Nixon Facility. The cost of the equipment was added to construction in progress. Once the equipment is placed in service, it will be reclassified to refinery and facilities and depreciation will begin. The equipment was delivered in December 2014. The long-term capital lease obligation requires a quarterly payment in the amount of $42,996. |
13_Treasury_Stock
13. Treasury Stock | 3 Months Ended |
Mar. 31, 2015 | |
Equity [Abstract] | |
Treasury Stock | At March 31, 2015 and December 31, 2014, we had 150,000 shares of treasury stock. |
14_Concentration_of_Risk
14. Concentration of Risk | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Risks and Uncertainties [Abstract] | |||||||||||||||||
Concentration of Risk | Key Supplier | ||||||||||||||||
Under the Crude Oil and Supply Throughput Services Agreement by and between LE and GEL dated August 12, 2011 (the “Crude Supply Agreement”), GEL is the exclusive supplier of crude oil and condensate to the Nixon Facility. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. The initial term was to expire on August 12, 2014. However, on October 30, 2013, LE entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam (the “October 2013 Letter Agreement”), effective October 24, 2013. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice. | |||||||||||||||||
Significant Customers | |||||||||||||||||
For the three months ended March 31, 2015, we had 3 customers that accounted for approximately 67% of our refined petroleum products sales. These 3 customers represented approximately $4.1 million in accounts receivable at March 31, 2015. For the three months ended March 31, 2014, we had 4 customers that accounted for approximately 87% of our refined petroleum products sales. These 4 customers represented approximately $7.4 million in accounts receivable at March 31, 2014. | |||||||||||||||||
Refined Petroleum Product Sales | |||||||||||||||||
All of our refined petroleum products are currently sold in the United States. The following table summarizes total refined petroleum product sales by distillation (from light to heavy): | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
LPG mix | $ | 57,308 | 0 | % | $ | 156,525 | 0.1 | % | |||||||||
Naphtha | 13,416,199 | 22 | % | 28,770,998 | 23.9 | % | |||||||||||
Jet fuel | 16,519,503 | 27.1 | % | 20,034,991 | 16.7 | % | |||||||||||
NRLM | - | 0 | % | 38,767,393 | 32.2 | % | |||||||||||
HOBM | 17,409,079 | 28.5 | % | - | 0 | % | |||||||||||
AGO | 13,664,973 | 22.4 | % | 32,646,244 | 27.1 | % | |||||||||||
$ | 61,067,062 | 100 | % | $ | 120,376,151 | 100 | % | ||||||||||
On May 31, 2014, the Nixon Facility ceased production of NRLM, a transportation-related diesel fuel product. On June 1, 2014, the Nixon Facility began producing heavy oil-based mud blendstock (“HOBM”), a non-transportation lubricant blend product. The shift in product slate from NRLM to HOBM was the result of the Environmental Protection Agency’s (the “EPA’s”) phased-in requirements for small refineries to reduce the sulfur content in transportation-related diesel fuel, such as NRLM, to a maximum of 15 ppm sulfur by June 1, 2014. “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s recently implemented fuel quality standards, and integration of such a unit generally requires additional permitting and significant capital upgrades. The Nixon Facility can produce and sell higher ppm sulfur diesel as a feedstock to other refineries and blenders in the United States and as a finished petroleum product to other countries. |
15_Leases
15. Leases | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [Abstract] | |
Leases | Our company headquarters is located in downtown Houston, Harris County, Texas. We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10 year term expiring in 2017, includes free rent periods and escalating rent payment provisions, and requires payment of a portion of related actual operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended March 31, 2015 and 2014, rent expense totaled $25,829. |
16_Income_Taxes
16. Income Taxes | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Income Tax Disclosure [Abstract] | |||||||||
Income Taxes | Income Tax Expense | ||||||||
Our income tax expense consisted of the following: | |||||||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
Current: | |||||||||
Federal | $ | (99,281 | ) | $ | (120,552 | ) | |||
State | (82,853 | ) | (81,871 | ) | |||||
Deferred: | |||||||||
Federal | (1,807,484 | ) | - | ||||||
State | - | - | |||||||
$ | (1,989,618 | ) | $ | (202,423 | ) | ||||
The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of TMT make it similar to an income tax. | |||||||||
Deferred Income Taxes | |||||||||
Blue Dolphin acquired 100% of the issued and outstanding membership interests of LE in 2012. As a limited liability company, LE’s taxable income or loss flowed through to its sole member for federal and state income tax purposes prior to the transaction. However, because Blue Dolphin is a “C” corporation, LE’s taxable income or loss now flows through to Blue Dolphin for federal and state income tax purposes. | |||||||||
Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. Blue Dolphin experienced ownership changes in 2005 in connection with a series of private placements, and in 2012 as a result of the LE transaction. The 2012 ownership change will subject NOL carryforwards to an annual use limitation, which will significantly reduce Blue Dolphin’s ability to use them to offset taxable income in periods following the 2012 ownership change. The amount of NOLs subject to such limitations is approximately $18.7 million. As a result of the limitation under IRC Section 382, the annual use limitation is $638,196 per year, the effect of which will result in approximately $6.7 million in NOL carryforwards expiring unused. | |||||||||
At March 31, 2015, approximately $4.0 million of net deferred tax asset remains available for future use, reflecting use of approximately $5.4 million of net operationg loss carryforwards through the period. At March 31, 2015, approximately $10.1 million of NOLs generated prior to the 2012 ownership change remain available for future use. At March 31, 2015, approximately $7.4 million of NOLs generated subsequent to the 2012 ownership change remain available for future use and are not subject to an annual use limitation under IRC Section 382. | |||||||||
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes. The following table shows significant components of our deferred tax assets and liabilities: | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Deferred tax assets: | |||||||||
Net operating loss and capital loss carryforwards | $ | 8,243,342 | $ | 10,067,144 | |||||
Start-up costs (Nixon Facility) | 1,613,702 | 1,648,036 | |||||||
Asset retirement obligations liability/deferred revenue | 873,236 | 869,821 | |||||||
AMT credit and other | 202,282 | 85,098 | |||||||
Total deferred tax assets | 10,932,562 | 12,670,468 | |||||||
Deferred tax liabilities: | |||||||||
Fair market value adjustments | (46,116 | ) | (46,116 | ) | |||||
Unrealized hedges | - | (168,606 | ) | ||||||
Basis differences in property and equipment | (4,663,502 | ) | (4,425,318 | ) | |||||
Total deferred tax liabilities | (4,709,618 | ) | (4,640,040 | ) | |||||
Deferred tax assets, net | 6,222,944 | 8,030,428 | |||||||
Valuation allowance | (2,270,322 | ) | (2,270,322 | ) | |||||
$ | 3,952,622 | $ | 5,760,106 | ||||||
The following table shows our current and noncurrent deferred tax assets (liabilities): | |||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Current deferred tax assets (liabilities) | $ | 17,779 | $ | (168,237 | ) | ||||
Noncurrent deferred tax assets, net | 6,205,165 | 8,198,665 | |||||||
Deferred tax assets, net | 6,222,944 | 8,030,428 | |||||||
Valuation allowance | (2,270,322 | ) | (2,270,322 | ) | |||||
$ | 3,952,622 | $ | 5,760,106 | ||||||
Valuation Allowance | |||||||||
As of each reporting date, management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets. As of March 31, 2015 and December 31, 2014, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $3.8 million and $5.7 million, respectively, were realizable, and as a result, reflected a valuation allowance accordingly. | |||||||||
Uncertain Tax Positions | |||||||||
We have 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. | |||||||||
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 three months ended March 31, 2015 and 2014. 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 March 31, 2015, fiscal years 2011 and later remain subject to examination by the IRS and fiscal years 2009 and later remain subject to examination by the state of Texas. We believe there are no uncertain tax positions for both federal and state income taxes. |
17_Earnings_Per_Share
17 Earnings Per Share | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Earnings Per Share [Abstract] | |||||||||
Earnings Per Share | The following table provides reconciliation between basic and diluted income per share: | ||||||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
Net income | $ | 3,701,364 | $ | 6,194,273 | |||||
Basic and diluted income per share | $ | 0.35 | $ | 0.59 | |||||
Basic and Diluted | |||||||||
Weighted average number of shares of common stock | |||||||||
outstanding and potential dilutive shares of common stock | 10,449,444 | 10,430,973 | |||||||
Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three months ended March 31, 2015 and 2014 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding. |
18_Fair_Value_Measurement
18. Fair Value Measurement | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurement | We are subject to gains or losses on certain financial assets based on our various agreements and understandings with Genesis. Pursuant to these agreements and understandings, Genesis may execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity price risks associated with our refined petroleum products and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil and condensate. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreement with Genesis, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments by Genesis. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded derivatives in our financial records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions executed on our behalf involving identical or comparable assets or liabilities. | ||||||||||||||||
The fair value hierarchy consists of the following three levels: | |||||||||||||||||
Level 1 | Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. | ||||||||||||||||
Level 2 | Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data. | ||||||||||||||||
Level 3 | Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs. | ||||||||||||||||
The carrying amounts of accounts receivable, accounts payable and accrued liabilities approximated their fair values at March 31, 2015 and December 31, 2014 due to their short-term maturities. The fair value of our long-term debt and short-term notes payable at March 31, 2015 and December 31, 2014 was $11,754,174 and $12,054,279, respectively. The fair value of our debt was determined using a Level 3 hierarchy. | |||||||||||||||||
The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014 and the basis for the measurement: | |||||||||||||||||
Fair Value Measurement at March 31, 2015 Using | |||||||||||||||||
Financial assets (liabilities): | Carrying Value at March 31, 2015 | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||||
Commodity contracts | $ | (52,290 | ) | $ | (52,290 | ) | $ | - | $ | - | |||||||
Fair Value Measurement at December 31, 2014 Using | |||||||||||||||||
Financial assets (liabilities): | Carrying Value at December 31, | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||||
2014 | |||||||||||||||||
Commodity contracts | $ | 495,900 | $ | 495,900 | $ | - | $ | - | |||||||||
Carrying amounts of commodity contracts executed by Genesis are reflected as other current assets or other current liabilities in our consolidated balance sheets. |
19_Refined_Petroleum_Products_
19. Refined Petroleum Products Inventory Risk Management | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||
Refined Petroleum Products Inventory Risk Management | Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled by Genesis with cash. | ||||||||||||
The fair value of these contracts is reflected in our consolidated balance sheets and the related net gain or loss is recorded within cost of refined petroleum products sold in our consolidated statements of operations. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end. | |||||||||||||
Commodity transactions are executed by Genesis to minimize transaction costs, monitor consolidated net exposures and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a futures contract is made solely by Genesis, Genesis typically confers with management as part of Genesis’ decision making process. | |||||||||||||
Due to mark-to-market accounting during the term of the commodity contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations. Additionally, Genesis may be required to collateralize any mark-to-market losses on outstanding commodity contracts. | |||||||||||||
As of March 31, 2015, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels): | |||||||||||||
Notional Contract Volumes by Year of Maturity | |||||||||||||
Inventory positions (futures): | 2015 | 2016 | 2017 | ||||||||||
Refined petroleum products and crude oil - net short positions | 145,000 | - | - | ||||||||||
The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2015 and December 31, 2014: | |||||||||||||
Fair Value | |||||||||||||
March 31, | December 31, | ||||||||||||
Asset Derivatives | Balance Sheets Location | 2015 | 2014 | ||||||||||
Commodity contracts | Prepaid expenses and other current assets (accrued expenses and other current liabilities) | $ | (52,290 | ) | $ | 495,900 | |||||||
The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2015 and 2014: | |||||||||||||
Gain (Loss) Recognized | |||||||||||||
Three Months Ended March 31, | |||||||||||||
Derivatives | Statements of Operations Location | 2015 | 2014 | ||||||||||
Commodity contracts | Cost of refined petroleum products sold | $ | 927,584 | $ | (181,569 | ) | |||||||
20_Commitments_and_Contingenci
20. Commitments and Contingencies | 3 Months Ended | ||
Mar. 31, 2015 | |||
Commitments and Contingencies Disclosure [Abstract] | |||
Commitments and Contingencies | Operating Agreement | ||
See “Note (9) Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement. | |||
Genesis Agreements | |||
LE was previously subject to three agreements with Genesis and its affiliates. Under the Construction and Funding Agreement, Milam committed funding for the completion of the Nixon Facility’s refurbishment and start-up operations. Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service. As a result of LE’s repayment of the full amount due to Milam under the Construction and Funding Agreement in May of 2014, LE now receives up to 80% of the Gross Profits as LE’s Profit Share under the Joint Marketing Agreement. | |||
Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows: | |||
● | Joint Marketing Agreement – Under the Joint Marketing Agreement, LE and GEL jointly market and sell the output produced at the Nixon Facility and share the Gross Profits (as defined below) from such sales. GEL is responsible for all product transportation scheduling; LE is responsible for entering into contracts with customers for the purchase and sale of output produced at the Nixon Facility and handling all billing and invoicing relating to the same. All payments for the sale of output produced at the Nixon Facility are made directly to GEL as collection agent and all customers must satisfy GEL’s customer credit approval process. Subject to certain amendments and clarifications (as described below), the Joint Marketing Agreement also provides for the sharing of “Gross Profits” (defined as the total revenue from the sale of output from the Nixon Facility minus the cost of crude oil and condensate pursuant to the Crude Supply Agreement). As a result of LE’s repayment of the full amount due and owing to Milam under the Construction and Funding Agreement, certain aspects related to the distribution of Gross Profits under the Joint Marketing Agreement no longer apply. Key applicable provisions are as follows: | ||
- | LE is entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees. If Gross Profits are insufficient to cover Operations Payments, then GEL may: (i) reduce Operations Payments by an amount representing the difference between the Operations Payments and the Gross Profits for such monthly period, or (ii) provide the Operations Payments with such Operations Payments being considered deficit amounts owing to GEL. If Gross Profits are negative, then LE is not entitled to receive Operations Payments and GEL may recoup any losses sustained by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated; and | ||
- | GEL is entitled to receive an administrative fee in the amount of $150,000 per month relating to the performance of its obligations under the Joint Marketing Agreement (the “Performance Fee”). GEL shall be paid 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share and LE shall be paid 70% of the remaining Gross Profit as the LE Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and LE in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) LE shall be paid 80% of the remaining Gross Profits over the Threshold Amount as the LE Profit Share. | ||
The Joint Marketing Agreement contains negative covenants that restrict LE’s actions under certain circumstances. For example, LE is prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement had an initial term of three years expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice; and | |||
● | Crude Supply Agreement – Under the Crude Supply Agreement, GEL is the exclusive supplier of crude oil and condensate to the Nixon Facility. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. GEL supplies crude oil and condensate to LE at cost plus freight expense and any costs associated with GEL’s hedging. All crude oil and condensate supplied to LE pursuant to the Crude Supply Agreement is paid for pursuant to the terms of the Joint Marketing Agreement as described above. In addition, GEL has a first right of refusal to use three storage tanks at the Nixon Facility during the term of the Crude Supply Agreement. Subject to certain termination rights, the Crude Supply Agreement had an initial term of three years expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, LE agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice. | ||
Master Easement Agreement - BDPL and FLNG | |||
Pursuant to a Master Easement Agreement dated December 11, 2013, BDPL provides FLNG Land, II, Inc., a Delaware corporation (“FLNG”) with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across the certain property of BDPL to certain property of FLNG (the “Access Easement”) and (ii) a pipeline easement and right of way across certain property of BDPL to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”). Under the agreement, FLNG will make payments in the amount of $500,000 to BDPL in October of each year through 2019. Thereafter, FLNG will make payments in the amount of $10,000 to BDPL in October of each year for so long as FLNG desires to use the Access Easement. | |||
Supplemental Pipeline Bonds | |||
We are required to satisfy supplemental pipeline bonding requirements of the Bureau of Ocean Energy Management (“BOEM”) with regard to certain pipelines that we operate in federal waters of the Gulf of Mexico. These supplemental pipeline bonding requirements are intended to secure our performance of plugging and abandonment obligations with respect to these pipelines. Once plugging and abandonment work has been completed, the collateral backing the supplemental pipeline bonds will be released. | |||
In August 2006, BDPL secured a $700,000 supplemental pipeline bond for Right-of-Way Number OCS-G 01381. On February 5, 2014, WBI and BDPL entered into a Purchase Agreement whereby BDPL reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. The $850,000 in cash was used to: (i) increase the supplemental pipeline bond for Right-of-Way Number OCS-G 01381 by $205,000, and (ii) secure a $645,000 supplemental pipeline bond for Right-of-Way Number OCS-G 08606. | |||
In December 2014, BDPL completed plugging and abandonment work for Right-of-Way Number OCS-G 08606. As a result, BDPL anticipates release of the cash-backed collateral for this supplemental pipeline bond by BOEM in the first half of 2015. There can be no assurance that BOEM will not require additional supplemental pipeline bonds related to other BDPL pipeline right-of-ways. | |||
Legal Matters | |||
From time to time we are subject to various lawsuits, claims, mechanics liens and administrative proceedings that arise out of the normal course of business. Management does not believe that liens, if any, will have a material adverse effect on our results of operations. | |||
Health, Safety and Environmental Matters | |||
All of our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of jet fuel and other products; and the monitoring, reporting and control of greenhouse gas emissions. Our operations also require numerous permits and authorizations under various environmental, health and safety laws and regulations. Failure to obtain and comply with these permits or environmental, health or safety laws generally could result in fines, penalties or other sanctions, or a revocation of our permits. |
3_Significant_Accounting_Polic1
3. Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [Abstract] | |
Use of Estimates | We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated. |
Cash and Cash Equivalents | Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents amounted to $2,279,206 and $1,293,233 at March 31, 2015 and December 31, 2014, respectively. |
Restricted Cash | Restricted cash represents a payment reserve account held by American First National Bank as security for payments under a 2008 loan agreement (the “Refinery Note”). Restricted cash was $1,011,112 and $1,008,514 at March 31, 2015 and December 31, 2014, respectively. |
Accounts Receivable, Allowance for Doubtful Accounts and Concentrations of Credit Risk | Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. |
Concentration of Risk | Bank Accounts |
Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $2,263,113 and $1,113,977 at March 31, 2015 and December 31, 2014, respectively. | |
Significant Customers | |
Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (14) Concentration of Risk” of this report for additional disclosures related to significant customers. | |
Inventory | The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products. Inventory reflected for crude oil and condensate is nominal and represents line fill. Because refined petroleum products are commodities, we have no control over the changing market value of these inventories. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated impairment expense. See “Note (7) Inventory” of this report for additional disclosures related to our inventory. |
Derivatives | We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash. |
Although these commodity futures contracts are not subject to hedge accounting treatment under FASB ASC guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statement of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting. | |
See “Note (18) Fair Value Measurement” and “Note (19) Refined Petroleum Products Inventory Risk Management” of this report for additional disclosures related to derivatives. | |
Property and Equipment | Refinery and Facilities |
Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance, including maintenance turnarounds, are expensed as incurred and are included as operating expenses under the Operating Agreement (see “Note (9) Accounts Payable Related Party” of this report for additional disclosures related to the Operating Agreement). Management expects to continue making improvements to the Nixon Facility based on technological advances. | |
Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the statements of operations. For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service. We did not record any impairment of our refinery and facilities for the three months ended March 31, 2015 and 2014. | |
Oil and Gas Properties | |
We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three months ended March 31, 2015 and 2014. All leases associated with our oil and gas properties have expired. | |
Pipelines and Facilities | |
We record pipelines and facilities at the lower of cost or net realizable value. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, assets are grouped and evaluated for impairment based on the ability to identify separate cash flows generated therefrom. | |
Construction in Progress | |
Construction in progress expenditures related to refurbishment activities at the Nixon Facility are capitalized as incurred. Depreciation begins once the asset is placed in service. | |
See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress. | |
Intangibles - Other | We have an acquisition-related intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014. |
Debt Issue Costs | We have debt issue costs related to certain facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to operations. Debt issue costs, net of accumulated amortization, totaled $500,122 and $479,737 at March 31, 2015 and December 31, 2014, respectively. Accumulated amortization was $219,693 and $211,244 at March 31, 2015 and December 31, 2014, respectively. Amortization expense, which is included in interest expense, was $8,450 for the three months ended March 31, 2015 and 2014. See “Note (12) Long-Term Debt” of this report for additional disclosures related to the Refinery Note. |
Revenue Recognition | Refined Petroleum Products Revenue |
We sell various refined petroleum products including jet fuel, naphtha, distillates and atmospheric gas oil (“AGO”). Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. | |
Customers assume the risk of loss when title is transferred. Transportation, shipping and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. | |
Tank Rental Revenue | |
Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. | |
Easement Revenue | |
Land easement revenue is recognized monthly as earned and is included in other income. | |
Pipeline Transportation Revenue | |
Revenue from our pipeline operations 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. | |
Deferred Revenue | |
On February 5, 2014, WBI Energy Midstream, LLC , a Colorado limited liability company (“WBI”), and BDPL entered into an Asset Sale Agreement (the “Purchase Agreement”) whereby BDPL reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid BDPL $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for the benefit of BDPL in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for BDPL’s benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure. | |
Income Taxes | We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. |
As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. | |
The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. | |
See “Note (16) Income Taxes” of this report for further information related to income taxes. | |
Impairment or Disposal of Long-Lived Assets | In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we initiate a review of our long-lived assets for impairment 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 comparing 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 that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. |
Asset Retirement Obligations | FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. |
Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. | |
We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating or disposing of our offshore platform, pipeline systems and related onshore facilities, as well as plugging and abandonment of wells and land and sea bed restoration costs. We developed 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 future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. | |
See “Note (11) Asset Retirement Obligations” of this report for additional information related to our AROs. | |
Computation of Earnings Per Share | We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income 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 our audited consolidated statements 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 available to common stockholders 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 shares of common stock were converted to common stock that then shared in the earnings of the entity. |
The number of shares related to options, warrants, restricted stock and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and for restricted stock the amount of compensation cost attributed to future services which has not yet been recognized and the amount of current and deferred tax benefit, if any, that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock and similar instruments is dependent on this average stock price and will increase as the average stock price increases. See “Note (17) Earnings Per Share” for additional information related to EPS. | |
Stock Based Compensation | In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period). |
Treasury Stock | We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (13) Treasury Stock” for additional disclosures related to treasury stock. |
Reclassification | We have reclassified certain insignificant prior period amounts related to our tank rental revenue to conform to our 2015 presentation. |
New Pronouncements Issued but Not Yet Effective | In May 2014, FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. ASU 2014-09 is currently effective for reporting periods beginning after December 15, 2016, and early adoption is not permitted. |
On April 1, 2015, FASB voted to propose a delay in the effective date of ASU 2014-09. As proposed, the new effective date would be annual reporting periods beginning after December 15, 2017, and the interim periods within that year. As such, for a public business entity with a calendar year-end, ASU 2014-09 would be effective on January 1, 2018, for both its interim and annual reporting periods. This proposal represents a one-year deferral from the original effective date. The proposed new effective date guidance would allow early adoption for all entities as of the original effective date (December 15, 2016). We are evaluating the impact that adoption of this guidance will have on the determination or reporting of our financial results. | |
In April 2015, FASB issued ASU 2015-03, Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. The amendments in this ASU are effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets. |
4_Business_Segment_Information1
4. Business Segment Information (Tables) | 3 Months Ended | ||||||||||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||
Business segment reporting | Business segment information for the three months ended March 31, 2015 and 2014 (and at March 31, 2015 and 2014), was as follows: | ||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2015 | Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||||||
Segment | Segment | ||||||||||||||||||||||||||||||||
Refinery | Pipeline | Corporate & | Refinery | Pipeline | Corporate & | ||||||||||||||||||||||||||||
Operations | Transportation | Other | Total | Operations | Transportation | Other | Total | ||||||||||||||||||||||||||
Revenue from operations | $ | 61,353,954 | $ | 38,395 | $ | - | $ | 61,392,349 | $ | 120,658,667 | $ | 54,031 | $ | - | $ | 120,712,698 | |||||||||||||||||
Less: cost of operations(1) | (52,259,470 | ) | (53,912 | ) | (408,048 | ) | (52,721,430 | ) | (113,368,578 | ) | (122,510 | ) | (334,729 | ) | (113,825,817 | ) | |||||||||||||||||
Other non-interest income | - | 62,500 | - | 62,500 | - | 125,000 | - | 125,000 | |||||||||||||||||||||||||
Adjusted EBITDA | 9,094,484 | 46,983 | (408,048 | ) | 8,733,419 | 7,290,089 | 56,521 | (334,729 | ) | 7,011,881 | |||||||||||||||||||||||
Less: JMA Profit Share(2) | (2,438,637 | ) | - | - | (2,438,637 | ) | - | - | - | - | |||||||||||||||||||||||
EBITDA | $ | 6,655,847 | $ | 46,983 | $ | (408,048 | ) | $ | 7,290,089 | $ | 56,521 | $ | (334,729 | ) | |||||||||||||||||||
Depletion, depreciation and amortization | (399,231 | ) | (390,605 | ) | |||||||||||||||||||||||||||||
Interest expense, net | (204,569 | ) | (224,580 | ) | |||||||||||||||||||||||||||||
Income before income taxes | $ | 5,690,982 | $ | 6,396,696 | |||||||||||||||||||||||||||||
Capital expenditures | $ | 1,291,915 | $ | - | $ | - | $ | 1,291,915 | $ | 59,178 | $ | - | $ | - | $ | 59,178 | |||||||||||||||||
Identifiable assets(3) | $ | 53,861,592 | $ | 2,923,368 | $ | 4,355,252 | $ | 61,140,212 | $ | 50,797,212 | $ | 3,201,220 | $ | 530,368 | $ | 54,528,800 |
5_Prepaid_Expenses_and_Other_C1
5. Prepaid Expenses and Other Current Assets (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Prepaid Expenses And Other Current Assets Tables | |||||||||
Prepaid balances | Prepaid expenses and other current assets consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Prepaid insurance | $ | 109,514 | $ | 156,558 | |||||
Prepaid listing fees | 11,250 | 15,000 | |||||||
Prepaid professional fees | - | 104,000 | |||||||
Unrealized hedging gains | - | 495,900 | |||||||
$ | 120,764 | $ | 771,458 |
6_Deposits_Tables
6. Deposits (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Deposits Tables | |||||||||
Deposit balances | Deposits consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Equipment deposits | $ | 100,463 | $ | 48,785 | |||||
Utility deposits | 10,250 | 10,250 | |||||||
Rent deposits | 9,463 | 9,463 | |||||||
$ | 120,176 | $ | 68,498 |
7_Inventory_Tables
7. Inventory (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Inventory Disclosure [Abstract] | |||||||||
Inventory | Inventory consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Jet fuel | $ | 1,859,729 | $ | 2,631,546 | |||||
Naphtha | 476,767 | 194,688 | |||||||
AGO | 453,098 | 224,007 | |||||||
HOBM | 252,657 | 124,176 | |||||||
Crude | 19,041 | 19,041 | |||||||
LPG mix | 9,418 | 7,193 | |||||||
$ | 3,070,710 | $ | 3,200,651 |
8_Property_Plant_and_Equipment1
8. Property, Plant and Equipment, Net (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Property, Plant and Equipment [Abstract] | |||||||||
Property and equipment | Property, plant and equipment, net, consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Refinery and facilities | $ | 36,547,078 | $ | 36,462,451 | |||||
Pipelines and facilities | 2,127,207 | 2,127,207 | |||||||
Onshore separation and handling facilities | 325,435 | 325,435 | |||||||
Land | 602,938 | 602,938 | |||||||
Other property and equipment | 627,479 | 597,064 | |||||||
40,230,137 | 40,115,095 | ||||||||
Less: Accumulated depletion, depreciation and amortization | (4,985,806 | ) | (4,586,575 | ) | |||||
35,244,331 | 35,528,520 | ||||||||
Construction in progress | 3,019,428 | 1,842,555 | |||||||
$ | 38,263,759 | $ | 37,371,075 |
10_Accrued_Expenses_and_Other_1
10. Accrued Expenses and Other Current Liabilities (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Accrued Expenses And Other Current Liabilities Tables | |||||||||
Accrued expenses and other current liabilities | Accrued expenses and other current liabilities consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Excise and income taxes payable | $ | 1,384,689 | $ | 1,228,411 | |||||
Genesis JMA Profit Share payable | 1,149,605 | 521,739 | |||||||
Transportation and inspection | 430,000 | 190,000 | |||||||
Board of director fees payable | 368,750 | 345,000 | |||||||
Unearned revenue | 220,631 | 252,500 | |||||||
Other payable | 103,580 | 149,962 | |||||||
Insurance | 64,062 | 96,092 | |||||||
Unrealized hedging loss | 52,290 | - | |||||||
$ | 3,773,607 | $ | 2,783,704 |
11_Asset_Retirement_Obligation1
11. Asset Retirement Obligations (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||
Asset retirement obligations | AROs on a roll-forward basis were as follows: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Asset retirement obligations, at the beginning of the period | $ | 1,866,770 | $ | 1,597,661 | |||||
New asset retirement obligations and adjustments | 49 | 300,980 | |||||||
Liabilities settled | - | (243,866 | ) | ||||||
Accretion expense | 53,215 | 211,995 | |||||||
1,920,034 | 1,866,770 | ||||||||
Less: current portion of asset retirement obligations | (86,341 | ) | (85,846 | ) | |||||
Long-term asset retirement obligations, at the end of the period | $ | 1,833,693 | $ | 1,780,924 |
12_LongTerm_Debt_Tables
12. Long-Term Debt (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Debt Disclosure [Abstract] | |||||||||
Long Term Debt | Long-term debt consisted of the following: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Refinery Note | $ | 8,545,466 | $ | 8,648,980 | |||||
Sovereign Loan | 1,479,949 | 1,638,898 | |||||||
Notre Dame Debt | 1,300,000 | 1,300,000 | |||||||
Capital Leases | 428,759 | 466,401 | |||||||
11,754,174 | 12,054,279 | ||||||||
Less: current portion of long-term debt | (1,263,057 | ) | (1,245,476 | ) | |||||
$ | 10,491,117 | $ | 10,808,803 | ||||||
Schedule of summary of equipment held under long-term capital leases | The following is a summary of equipment held under long-term capital leases: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Cost | $ | 538,598 | $ | 538,598 | |||||
Less: accumulated depreciation | - | - | |||||||
$ | 538,598 | $ | 538,598 |
14_Concentration_of_Risk_Table
14. Concentration of Risk (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Concentration Of Risk Tables | |||||||||||||||||
Percentages of all refined petroleum products sales to total sales | The following table summarizes total refined petroleum product sales by distillation (from light to heavy): | ||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2015 | 2014 | ||||||||||||||||
LPG mix | $ | 57,308 | 0 | % | $ | 156,525 | 0.1 | % | |||||||||
Naphtha | 13,416,199 | 22 | % | 28,770,998 | 23.9 | % | |||||||||||
Jet fuel | 16,519,503 | 27.1 | % | 20,034,991 | 16.7 | % | |||||||||||
NRLM | - | 0 | % | 38,767,393 | 32.2 | % | |||||||||||
HOBM | 17,409,079 | 28.5 | % | - | 0 | % | |||||||||||
AGO | 13,664,973 | 22.4 | % | 32,646,244 | 27.1 | % | |||||||||||
$ | 61,067,062 | 100 | % | $ | 120,376,151 | 100 | % |
16_Income_Taxes_Tables
16. Income Taxes (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Income Tax Disclosure [Abstract] | |||||||||
Income tax benefit (expense) | Our income tax expense consisted of the following: | ||||||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
Current: | |||||||||
Federal | $ | (99,281 | ) | $ | (120,552 | ) | |||
State | (82,853 | ) | (81,871 | ) | |||||
Deferred: | |||||||||
Federal | (1,807,484 | ) | - | ||||||
State | - | - | |||||||
$ | (1,989,618 | ) | $ | (202,423 | ) | ||||
Deferred tax assets and deferred tax liabilities | The following table shows significant components of our deferred tax assets and liabilities: | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Deferred tax assets: | |||||||||
Net operating loss and capital loss carryforwards | $ | 8,243,342 | $ | 10,067,144 | |||||
Start-up costs (Nixon Facility) | 1,613,702 | 1,648,036 | |||||||
Asset retirement obligations liability/deferred revenue | 873,236 | 869,821 | |||||||
AMT credit and other | 202,282 | 85,098 | |||||||
Total deferred tax assets | 10,932,562 | 12,670,468 | |||||||
Deferred tax liabilities: | |||||||||
Fair market value adjustments | (46,116 | ) | (46,116 | ) | |||||
Unrealized hedges | - | (168,606 | ) | ||||||
Basis differences in property and equipment | (4,663,502 | ) | (4,425,318 | ) | |||||
Total deferred tax liabilities | (4,709,618 | ) | (4,640,040 | ) | |||||
Deferred tax assets, net | 6,222,944 | 8,030,428 | |||||||
Valuation allowance | (2,270,322 | ) | (2,270,322 | ) | |||||
$ | 3,952,622 | $ | 5,760,106 | ||||||
Current and noncurrent deferred tax assets (liabilities) | The following table shows our current and noncurrent deferred tax assets (liabilities): | ||||||||
March 31, | December 31, | ||||||||
2015 | 2014 | ||||||||
Current deferred tax assets (liabilities) | $ | 17,779 | $ | (168,237 | ) | ||||
Noncurrent deferred tax assets, net | 6,205,165 | 8,198,665 | |||||||
Deferred tax assets, net | 6,222,944 | 8,030,428 | |||||||
Valuation allowance | (2,270,322 | ) | (2,270,322 | ) | |||||
$ | 3,952,622 | $ | 5,760,106 |
17_Earnings_Per_Share_Tables
17. Earnings Per Share (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Earnings Per Share [Abstract] | |||||||||
Earnings per share | The following table provides reconciliation between basic and diluted income (loss) per share: | ||||||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
Net income | $ | 3,701,364 | $ | 6,194,273 | |||||
Basic and diluted income per share | $ | 0.35 | $ | 0.59 | |||||
Basic and Diluted | |||||||||
Weighted average number of shares of common stock | |||||||||
outstanding and potential dilutive shares of common stock | 10,449,444 | 10,430,973 |
18_Fair_Value_Measurement_Tabl
18. Fair Value Measurement (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Fair Value Measurement | The following table represents our assets and liabilities measured at fair value on a recurring basis as of March 31, 2015 and December 31, 2014 and the basis for the measurement: | ||||||||||||||||
Fair Value Measurement at March 31, 2015 Using | |||||||||||||||||
Financial assets (liabilities): | Carrying Value at March 31, 2015 | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||||
Commodity contracts | $ | (52,290 | ) | $ | (52,290 | ) | $ | - | $ | - | |||||||
Fair Value Measurement at December 31, 2014 Using | |||||||||||||||||
Financial assets (liabilities): | Carrying Value at December 31, | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||||
2014 | |||||||||||||||||
Commodity contracts | $ | 495,900 | $ | 495,900 | $ | - | $ | - | |||||||||
21_Refined_Products_Inventory_
21. Refined Products Inventory Risk Management (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||
Notional volume of outstanding contracts by type of instrument | The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels): | ||||||||||||
Inventory positions (futures): | 2015 | 2016 | 2017 | ||||||||||
Refined petroleum products and crude oil - net short positions | 145,000 | - | - | ||||||||||
Fair value amounts of derivative instruments | The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at March 31, 2015 and December 31, 2014: | ||||||||||||
Fair Value | |||||||||||||
March 31, | December 31, | ||||||||||||
Asset Derivatives | Balance Sheets Location | 2015 | 2014 | ||||||||||
Commodity contracts | Prepaid expenses and other current assets (accrued expenses and other current liabilities) | $ | (52,290 | ) | $ | 495,900 | |||||||
Effect of derivative instruments | The following table provides the effect of derivative instruments in our consolidated statements of operations for the three months ended March 31, 2015 and 2014: | ||||||||||||
Gain (Loss) Recognized | |||||||||||||
Three Months Ended March 31, | |||||||||||||
Derivatives | Statements of Operations Location | 2015 | 2014 | ||||||||||
Commodity contracts | Cost of refined petroleum products sold | $ | 927,584 | $ | (181,569 | ) | |||||||
1_Organization_Details
1. Organization (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 |
Organization Details | ||||
Cash and cash equivalents | $2,279,206 | $1,293,233 | $295,877 | $434,717 |
3_Significant_Accounting_Polic2
3. Significant Accounting Policies (Details Narrative) (USD $) | 3 Months Ended | |||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $2,279,206 | $295,877 | $1,293,233 | $434,717 |
Restricted cash | 1,011,112 | 1,008,514 | ||
FDIC limit per depositer | 250,000 | |||
Cash balances in excess of the FDIC insurance limit per depositor | 2,263,113 | 1,113,977 | ||
Accumulated amortization | 219,693 | 211,244 | ||
Amortization expense | 8,450 | 8,450 | ||
Debt issuance costs | $500,122 | $479,737 |
4_Business_Segment_Information2
4. Business Segment Information (Details) (USD $) | 3 Months Ended | |||
Mar. 31, 2015 | Mar. 31, 2014 | |||
Revenue from operations | $61,392,349 | $120,712,698 | ||
Refinery Operations [Member] | ||||
Revenue from operations | 61,353,954 | 120,658,667 | ||
Less: cost of operations | -52,259,470 | [1] | -113,368,578 | [1] |
Other non-interest income | ||||
Adjusted EBITDA | 9,094,484 | 7,290,089 | ||
Less: JMA Profit Share | -2,438,637 | [2] | [2] | |
EBITDA | 6,655,847 | 7,290,089 | ||
Capital expenditures | 1,291,915 | 59,178 | ||
Identifiable assets | 53,861,592 | [3] | 50,797,212 | [3] |
Pipeline Transportation [Member] | ||||
Revenue from operations | 38,395 | 54,031 | ||
Less: cost of operations | -53,912 | [1] | -122,510 | [1] |
Other non-interest income | 62,500 | 125,000 | ||
Adjusted EBITDA | 46,983 | 56,521 | ||
Less: JMA Profit Share | [2] | [2] | ||
EBITDA | 46,983 | 56,521 | ||
Capital expenditures | ||||
Identifiable assets | 2,923,368 | [3] | 3,201,220 | [3] |
Corporate and Other [Member] | ||||
Revenue from operations | ||||
Less: cost of operations | -408,048 | [1] | -334,729 | [1] |
Other non-interest income | ||||
Adjusted EBITDA | -408,048 | -334,729 | ||
Less: JMA Profit Share | [2] | [2] | ||
EBITDA | -408,048 | -334,729 | ||
Capital expenditures | ||||
Identifiable assets | 4,355,252 | [3] | 530,368 | [3] |
Total | ||||
Revenue from operations | 61,392,349 | 120,712,698 | ||
Less: cost of operations | -52,721,430 | [1] | -113,825,817 | [1] |
Other non-interest income | 62,500 | 125,000 | ||
Adjusted EBITDA | 8,733,419 | 7,011,881 | ||
Less: JMA Profit Share | -2,438,637 | [2] | [2] | |
Depletion, depreciation and amortization | -399,231 | -390,605 | ||
Interest expense, net | -204,569 | -224,580 | ||
Income before income taxes | 5,690,982 | 6,396,696 | ||
Capital expenditures | 1,291,915 | 59,178 | ||
Identifiable assets | $61,140,212 | [3] | $54,528,800 | [3] |
[1] | Operation cost within the "Refinery Operations" and "Pipeline Transportation" segments includes related general, administrative, and accretion expenses. Operation cost within "Corporate and Other" includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees and legal expense. | |||
[2] | The Joint Marketing Agreement profit share (the "JMA Profit Share") represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See "Part 1, Item 1 - Note (20) Commitments and Contingencies" and "Part 1, Item 2. Management's Discussion and Analysis and Results of Operations - Relationship with Genesis" of this report for further discussion of the Joint Marketing Agreement. | |||
[3] | Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable and recorded net assets. |
5_Prepaid_Expenses_and_Other_C2
5. Prepaid Expenses and Other Current Assets (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Prepaid Expenses And Other Current Assets Details | ||
Prepaid insurance | $109,514 | $156,558 |
Prepaid listing fees | 11,250 | 15,000 |
Prepaid professional fees | 104,000 | |
Unrealized hedging gains | 495,900 | |
Prepaid Expenses, Net | $120,764 | $771,458 |
6_Deposits_Details
6. Deposits (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Deposits Details | ||
Equipment deposits | $100,463 | $48,785 |
Utility deposits | 10,250 | 10,250 |
Rent deposits | 9,463 | 9,463 |
Deposits | $120,176 | $68,498 |
7_Inventory_Details
7. Inventory (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Inventory Disclosure [Abstract] | ||
Jet fuel | $1,859,729 | $2,631,546 |
Naphtha | 476,767 | 194,688 |
AGO | 453,098 | 224,007 |
HOBO | 252,657 | 124,176 |
Crude | 19,041 | 19,041 |
LPG mix | 9,418 | 7,193 |
Inventories, Net | $3,070,710 | $3,200,651 |
8_Property_Plant_and_Equipment2
8. Property, Plant and Equipment, Net (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Property Plant And Equipment Net Details | ||
Refinery and facilities | $36,547,078 | $36,462,451 |
Pipelines and facilities | 2,127,207 | 2,127,207 |
Onshore separation and handling facilities | 325,435 | 325,435 |
Land | 602,938 | 602,938 |
Other property and equipment | 627,479 | 597,064 |
Property, Plant and Equipment, Gross | 40,230,137 | 40,115,095 |
Less: Accumulated depletion, depreciation and amortization | -4,985,806 | -4,586,575 |
Property, Plant and Equipment less depreciation | 35,244,331 | 35,528,520 |
Construction in progress | 3,019,428 | 1,842,555 |
Property, Plant and Equipment, Net | $38,263,759 | $37,371,075 |
9_Accounts_Payable_Related_Par1
9. Accounts Payable, Related Party Transactions (Details Narrative) (USD $) | 3 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Payables and Accruals [Abstract] | |||
Expense for service | $2,880,971 | $2,955,019 | |
Accounts payable, related party | $119,645 | $1,174,168 |
10_Accrued_Expenses_and_Other_2
10. Accrued Expenses and Other Current Liabilities (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Accrued Expenses And Other Current Liabilities Details | ||
Excise and income taxes payable | $1,384,689 | $1,228,411 |
Genesis JMA Profit Share payable | 1,149,605 | 521,739 |
Transportation and inspection | 430,000 | 190,000 |
Board of director fees payable | 368,750 | 345,000 |
Unearned revenue | 220,631 | 252,500 |
Other payable | 103,580 | 149,962 |
Insurance | 64,062 | 96,092 |
Unrealized hedging loss | 52,290 | |
Accrued Expenses and Other Current Liabilities, Net | $3,773,607 | $2,783,704 |
11_Asset_Retirement_Obligation2
11. Asset Retirement Obligations (Details) (USD $) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Asset Retirement Obligations Details | |||
Asset retirement obligations, at the beginning of the period | $1,866,770 | $1,597,661 | $1,597,661 |
New asset retirement obligations and adjustments | 49 | 300,980 | |
Liabilities settled | -243,866 | ||
Accretion expense | 53,215 | 50,802 | 211,995 |
Asset retirement obligations as of March 31, 2015 | 1,920,034 | 1,866,770 | |
Less: current portion of asset retirement obligations | -86,341 | -85,846 | |
Long-term asset retirement obligations, at the end of the period | $1,833,693 | $1,780,924 |
12_LongTerm_Debt_Details
12. Long-Term Debt (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Debt Disclosure [Abstract] | ||
Refinery Note | $8,545,466 | $8,648,980 |
Sovereign Loan | 1,479,949 | 1,638,898 |
Notre Dame Debt | 1,300,000 | 1,300,000 |
Capital leases | 428,759 | 466,401 |
Total | 11,754,174 | 12,054,279 |
Less: Current portion of long-term debt | -1,263,057 | -1,245,476 |
Long term debt | $10,491,117 | $10,808,803 |
12_LongTerm_Debt_Details_1
12. Long-Term Debt (Details 1) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Debt Disclosure [Abstract] | ||
Cost | $538,598 | $538,598 |
Less: Accumulated depreciation | ||
Capital lease obligation | $538,598 | $538,598 |
12_LongTerm_Debt_Details_Narra
12. Long-Term Debt (Details Narrative) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Debt Disclosure [Abstract] | ||
Refinery Note | $8,545,466 | $8,648,980 |
Refinery loan accrued interest | 35,997 | 47,569 |
Notre Dame debt accrued interest | 1,326,080 | 1,274,789 |
Sovereign Loan | 1,479,949 | 1,638,898 |
Sovereign Loan Accrued Interest | 7,649 | 8,470 |
Capital leases | 428,759 | 466,401 |
Notre Dame Debt | $1,300,000 | $1,300,000 |
13_Treasury_Stock_Details_Narr
13. Treasury Stock (Details Narrative) | Mar. 31, 2015 | Dec. 31, 2014 |
Treasury Stock Details Narrative | ||
Treasury stock | 150,000 | 150,000 |
14_Concentration_of_Risk_Detai
14. Concentration of Risk (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Total refined petroleum product sales | $61,067,062 | $120,376,151 |
Concentration Risk | 100.00% | 100.00% |
LPG mix | ||
Total refined petroleum product sales | 57,308 | 156,525 |
Concentration Risk | 0.00% | 0.10% |
Naphtha | ||
Total refined petroleum product sales | 13,416,199 | 28,770,998 |
Concentration Risk | 22.00% | 23.90% |
Jet Fuel | ||
Total refined petroleum product sales | 16,519,503 | 20,034,991 |
Concentration Risk | 27.10% | 16.70% |
NRLM | ||
Total refined petroleum product sales | 38,767,393 | |
Concentration Risk | 0.00% | 32.20% |
HOBM | ||
Total refined petroleum product sales | 17,409,079 | |
Concentration Risk | 28.50% | 0.00% |
AGO | ||
Total refined petroleum product sales | $13,664,973 | $32,646,244 |
Concentration Risk | 22.40% | 27.10% |
14_Concentration_of_Risk_Detai1
14. Concentration of Risk (Details Narrative ) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Concentration Risk | 100.00% | 100.00% |
Account receivable [Member] | Four customers [Member] | ||
Accounts receivable | 7,400,000 | |
Account receivable [Member] | Three customers [Member] | ||
Accounts receivable | 4,100,000 | |
Sales Revenue [Member] | Four customers [Member] | ||
Concentration Risk | 87.00% | |
Sales Revenue [Member] | Three customers [Member] | ||
Concentration Risk | 67.00% |
15_Leases_Details_Narrative
15. Leases (Details Narrative) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Leases Details Narrative | ||
Rent expense | $25,829 | $25,829 |
16_Income_Taxes_Details
16. Income Taxes (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Current: | ||
Federal | ($99,281) | ($120,552) |
State | -82,853 | -81,871 |
Deferred: | ||
Federal | -1,807,484 | |
State | ||
Income tax benefit (expense) | ($1,989,618) | ($202,423) |
16_Income_Taxes_Details_1
16. Income Taxes (Details 1) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Deferred tax assets: | ||
Net operating loss and capital loss carryforwards | $8,243,342 | $10,067,144 |
Start-up costs (Nixon Facility) | 1,613,702 | 1,648,036 |
Asset retirement obligations liability/deferrred revenue | 873,236 | 869,821 |
AMT credit and other | 202,282 | 85,098 |
Total deferred tax assets | 10,932,562 | 12,670,468 |
Deferred tax liabilities: | ||
Fair market value adjustments | -46,116 | -46,116 |
Unrealized hedges | -168,606 | |
Basis differences in property and equipment | -4,663,502 | -4,425,318 |
Total deferred tax liabilities | -4,709,618 | -4,640,040 |
Deferred tax assets, net | 6,222,944 | 8,030,428 |
Valuation allowance | -2,270,322 | -2,270,322 |
Deferred tax assets and liabilities, net | $3,952,622 | $5,760,106 |
16_Income_Taxes_Details_2
16. Income Taxes (Details 2) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Income Taxes Details 3 | ||
Current deferred tax assets (liabilities) | $17,779 | |
Noncurrent deferred tax assets, net | 6,205,165 | 8,198,665 |
Deferred tax assets, net | 6,222,944 | 8,030,428 |
Valuation allowance | -2,270,322 | -2,270,322 |
Deferred tax assets and liabilities, net | $3,952,622 | $5,760,106 |
16_Income_Taxes_Details_Narrat
16. Income Taxes (Details Narrative) (USD $) | Mar. 31, 2015 |
Income Taxes Details 1 | |
Amount of NOLs | $10,100,000 |
Post-merger NOLs | $7,400,000 |
17_Earnings_per_share_Details
17. Earnings per share (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Earnings Per Share [Abstract] | ||
Net income | $3,701,364 | $6,194,273 |
Basic and diluted income per share | $0.35 | $0.59 |
Basic and diluted | ||
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock | 10,449,444 | 10,430,973 |
18_Fair_Value_Measurement_Deta
18. Fair Value Measurement (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Financial assets (liabilties): | ||
Commodity contracts | ($52,290) | $495,900 |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts | -52,290 | 495,900 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts | ||
Significant Unobservable Inputs (Level 3) [Member] | ||
Financial assets (liabilties): | ||
Commodity contracts |
18_Fair_Value_Measurement_Deta1
18. Fair Value Measurement (Details Narrative) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Fair Value Measurement Details Narrative | ||
Fair value of long term debt and short-term notes payable | $11,754,174 | $12,054,279 |
19_Refined_Petroleum_Products_1
19. Refined Petroleum Products Inventory Risk Management (Details) (Refined products - net short (long) positions) | Mar. 31, 2015 |
Refined products - net short (long) positions | |
Volume in Thousands of barrels | |
Notional Contract Volumes 2015 | 145,000 |
Notional Contract Volumes 2016 | |
Notional Contract Volumes 2017 |
19_Refined_Petroleum_Products_2
19. Refined Petroleum Products Inventory Risk Management (Details 1) (Commodity Contracts, USD $) | 3 Months Ended | ||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | |
Commodity Contracts | |||
Prepaid expenses and other current assets (accrued expenses and other current liabilities) | ($52,290) | $495,900 | |
Cost of refined petroleum products sold | $927,584 | ($181,569) |