Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Aug. 14, 2018 | |
Document And Entity Information | ||
Entity Registrant Name | BLUE DOLPHIN ENERGY CO | |
Entity Central Index Key | 793,306 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2018 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
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 | 10,925,513 | |
Document Fiscal Period Focus | Q2 | |
Document Fiscal Year Focus | 2,018 |
Consolidated Balance Sheets (Un
Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 361 | $ 495 |
Restricted cash | 49 | 49 |
Accounts receivable, net | 1,105 | 1,357 |
Accounts receivable, related party | 0 | 653 |
Prepaid expenses and other current assets | 2,317 | 1,207 |
Deposits | 195 | 129 |
Inventory | 4,180 | 3,089 |
Refundable federal income tax | 108 | 0 |
Total current assets | 8,315 | 6,979 |
Total property and equipment, net | 64,992 | 64,597 |
Restricted cash, noncurrent | 1,602 | 1,602 |
Surety bonds | 230 | 230 |
Deferred tax assets, net | 108 | 0 |
Total long-term assets | 66,932 | 66,429 |
TOTAL ASSETS | 75,247 | 73,408 |
CURRENT LIABILITIES | ||
Long-term debt less unamortized debt issue costs, current portion, in default | 35,194 | 35,544 |
Long-term debt, related party, current portion | 6,060 | 4,000 |
Interest payable | 2,529 | 2,135 |
Interest payable, related party | 1,214 | 892 |
Accounts payable | 1,958 | 2,344 |
Accounts payable, related party | 1,226 | 974 |
Asset retirement obligations, current portion | 2,458 | 2,315 |
Accrued expenses and other current liabilities | 3,487 | 1,160 |
Accrued arbitration award payable | 24,128 | 27,128 |
Total current liabilities | 78,254 | 76,492 |
Long-term liabilities: | ||
Deferred revenues and expenses | 21 | 42 |
Capital lease obligation, net of current portion | 21 | 0 |
Long-term debt, related party, net of current portion | 0 | 1,608 |
Total long-term liabilities | 42 | 1,650 |
TOTAL LIABILITIES | 78,296 | 78,142 |
Commitments and contingencies (Note 18) | ||
STOCKHOLDERS' EQUITY (DEFICIT) | ||
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,925,513 shares issued at June 30, 2018 and December 31, 2017, respectively) | 109 | 109 |
Additional paid-in capital | 36,907 | 36,907 |
Accumulated deficit | (40,065) | (41,750) |
Total stockholders' equity (deficit) | (3,049) | (4,734) |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) | $ 75,247 | $ 73,408 |
Consolidated Balance Sheets (U3
Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
STOCKHOLDERS' EQUITY | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares issued | 10,925,513 | 10,925,513 |
Common stock, shares Outstanding | 10,925,513 | 10,925,513 |
Consolidated Statements of Oper
Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
REVENUE FROM OPERATIONS | ||||
Refinery operations | $ 88,265 | $ 56,633 | $ 159,777 | $ 108,535 |
Tolling and terminaling | 850 | 704 | 1,584 | 1,407 |
Total revenue from operations | 89,115 | 57,337 | 161,361 | 109,942 |
COST OF OPERATIONS | ||||
Cost of refined products sold | 83,867 | 54,625 | 152,591 | 106,399 |
Refinery operating expenses | 1,377 | 1,652 | 3,299 | 4,465 |
Other operating expenses | 56 | 54 | 100 | 115 |
Arbitration award and associated fees | 0 | 24,339 | 0 | 24,339 |
General and administrative expenses | 688 | 708 | 1,348 | 1,614 |
Depletion, depreciation and amortization | 463 | 449 | 918 | 900 |
Accretion of asset retirement obligations | 78 | 72 | 143 | 144 |
Total cost of operations | 86,529 | 81,899 | 158,400 | 137,976 |
Income (loss) from operations | 2,586 | (24,562) | 2,961 | (28,034) |
OTHER INCOME (EXPENSE) | ||||
Easement, interest and other income | 1 | 1 | 2 | 383 |
Interest and other expense | (751) | (832) | (1,495) | (1,426) |
Gain on disposal of property | 0 | 0 | 0 | 1,834 |
Total other income (expense) | (750) | (831) | (1,493) | 791 |
Income (loss) before income taxes | 1,836 | (25,393) | 1,468 | (27,243) |
Income tax benefit | 0 | 0 | 217 | 0 |
Net income (loss) | $ 1,836 | $ (25,393) | $ 1,685 | $ (27,243) |
Loss per common share: | ||||
Basic | $ 0.17 | $ (2.39) | $ 0.15 | $ (2.58) |
Diluted | $ 0.17 | $ (2.39) | $ 0.15 | $ (2.58) |
Weighted average number of common shares outstanding: | ||||
Basic | 10,925,513 | 10,637,101 | 10,925,513 | 10,556,356 |
Diluted | 10,925,513 | 10,637,101 | 10,925,513 | 10,556,356 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
OPERATING ACTIVITIES | |||||
Net loss | $ 1,836 | $ (25,393) | $ 1,685 | $ (27,243) | |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | |||||
Depletion, depreciation and amortization | 918 | 900 | |||
Deferred income tax | (216) | 0 | |||
Amortization of debt issue costs | 64 | 64 | |||
Accretion of asset retirement obligations | 78 | 72 | 143 | 144 | $ 287 |
Common stock issued for services | 0 | 30 | |||
Changes in operating assets and liabilities | |||||
Accounts receivable | 252 | 1,586 | |||
Accounts receivable, related party | 653 | 1,162 | |||
Prepaid expenses and other current assets | (1,110) | (57) | |||
Deposits and other assets | (66) | (25) | |||
Inventory | (1,091) | (1,773) | |||
Accrued arbitration award | (3,000) | 31,279 | |||
Accounts payable, accrued expenses and other liabilities | 2,635 | (11,336) | |||
Accounts payable, related party | 252 | 302 | |||
Net cash provided by (used in) operating activities | 1,120 | (4,967) | |||
INVESTING ACTIVITIES | |||||
Capital expenditures | (1,231) | (1,408) | |||
Net cash used in investing activities | (1,231) | (1,408) | |||
FINANCING ACTIVITIES | |||||
Payments on debt | (475) | (855) | |||
Net activity on related-party debt | 452 | 3,257 | |||
Net cash provided by financing activities | (23) | 2,402 | |||
Net change in cash, cash equivalents, and restricted cash | (134) | (3,973) | |||
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF PERIOD | 2,146 | 6,083 | 6,083 | ||
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD | $ 2,012 | $ 2,110 | 2,012 | 2,110 | $ 2,146 |
Non-cash investing and financing activities: | |||||
Financing of capital expenditures via accounts payable | 82 | 1,462 | |||
Financing of guaranty fees via long-term debt, related party | 325 | 111 | |||
Conversion of accounts payable to short-term notes | 0 | 0 | |||
Conversion of related-party notes to common stock | 0 | 831 | |||
Interest paid | 1,290 | 1,333 | |||
Income taxes paid | $ 0 | $ 0 |
1. Organization
1. Organization | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Nature of Operations Structure and Management We have the following active subsidiaries: ● Nixon Product Storage, LLC, a Delaware limited liability company (“NPS”). ● Lazarus Energy, LLC, a Delaware limited liability company (“LE”). ● Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”). ● Blue Dolphin Pipe Line Company, a Delaware corporation (“BDPL”). ● Blue Dolphin Petroleum Company, a Delaware corporation. ● Blue Dolphin Services Co., a Texas corporation (“BDSC”). Effective June 12, 2018, Blue Dolphin acquired 100% of the issued and outstanding membership interests of NPS from Lazarus Midstream Partners, L.P., an affiliate of LEH, pursuant to an Assignment Agreement. The assignment was accounted for as a combination of entities under common control. See “Note (5) NPS Assignment” of this Quarterly Report for further information related to the NPS assignment. See "Part I, Item 1. Business” and “Item 2. Properties” in the Annual Report for additional information regarding our operating subsidiaries, principal facilities, and assets. References in this Quarterly Report to “we,” “us,” and “our” are to Blue Dolphin and its subsidiaries unless otherwise indicated or the context otherwise requires. Going Concern ● Final Arbitration Award and Settlement Agreement – As previously disclosed, LE was involved in arbitration proceedings (the “GEL Arbitration”) with GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis Energy, LP (“Genesis”), related to a contractual dispute involving a Crude Oil Supply and Throughput Services Agreement (the “Crude Supply Agreement”) and a Joint Marketing Agreement (the “Joint Marketing Agreement”), each between LE and GEL and dated August 12, 2011. On August 11, 2017, the arbitrator delivered its final award in the GEL Arbitration (the “Final Arbitration Award”). The Final Arbitration Award denied all of LE’s claims against GEL and granted substantially all the relief requested by GEL in its counterclaims. Among other matters, the Final Arbitration Award awarded damages and GEL’s attorneys’ fees and related expenses to GEL in the aggregate amount of approximately $31.3 million. As of the date of this report, LE has paid $7.6 million to GEL, which amount has been applied to reduce the balance of the Final Arbitration Award. As previously disclosed, a hearing on confirmation of the Final Arbitration Award was scheduled to occur on September 18, 2017 in state district court in Harris County, Texas. Prior to the scheduled hearing, LE and GEL jointly notified the court that the hearing would be continued for a period of no more than 90 days after September 18, 2017 (the “Continuance Period”), to facilitate settlement discussions between the parties. On September 26, 2017, LE and Blue Dolphin, together with LEH and Jonathan Carroll, entered into a Letter Agreement with GEL, effective September 18, 2017 (the “GEL Letter Agreement”), confirming the parties’ agreement to the continuation of the confirmation hearing during the Continuance Period, subject to the terms of the GEL Letter Agreement. The GEL Letter Agreement was subsequently amended nine times to extend the Continuance Period through July 2018. On July 20, 2018, LE, NPS, and Blue Dolphin, together with LEH, Carroll & Company Financial Holdings, L.P. (“C&C”), and Jonathan Carroll (collectively referred to herein as the “Lazarus Parties”), entered into a Settlement Agreement with GEL (the “Settlement Agreement”), whereby GEL and the Lazarus Parties agreed to mutually release all claims against each other and to file a stipulation of dismissal with prejudice in connection with the GEL Arbitration (the “Settlement”), subject to the terms and conditions set forth in the Settlement Agreement. The Settlement is conditioned upon payment by the Lazarus Parties to GEL of $10.0 million in cash (the “Settlement Payment”) and $0.5 million in cash at the end of each calendar month until the Settlement Payment is paid (the “Interim Payments”) or the Settlement Agreement is terminated. The Interim Payments will not be applied to reduce the amount of the Settlement Payment, but such payments will reduce the Final Arbitration Award. At June 30, 2018 and December 31, 2017, accrued arbitration award payable on our consolidated balance sheet was $24.1 million and $27.1 million, respectively. At the time of the Settlement, the difference between the Settlement Payment and the amount we have accrued on our consolidated balance sheet for arbitration award payable will be recognized as a gain on our consolidated statement of operations. The Settlement Agreement restricts the Lazarus Parties from taking certain actions without the prior written consent of GEL, including: (i) the incurrence of any debt not specifically excepted in the Settlement Agreement, (ii) the establishment of any liens not specifically excepted in the Settlement Agreement, (iii) the disposition of any assets other than certain ordinary course sales to unaffiliated third parties, payments to unaffiliated third-party trade creditors and scheduled debt payments, (iv) the entrance into any transactions with affiliates not specifically excepted in the Settlement Agreement, (v) the failure to pay debts generally as they become due, and (vi) the entrance into a bankruptcy, reorganization or similar proceeding. A violation of any of the restrictions in the Settlement Agreement, as well as the failure of the Lazarus Parties to make Interim Payments as they become due, will constitute an event of default under the Settlement Agreement which, subject to certain cure periods, would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award. The Lazarus Parties are exploring the possibility of obtaining a commercial loan in an aggregate principal amount equal to the Settlement Payment (the “Settlement Financing”), subject to obtaining the consent of Veritex Community Bank (“Veritex”), as lender under certain loan agreements with the Lazarus Parties and their affiliates. Under the Settlement Agreement, the Lazarus Parties are required to work in good faith and take reasonable actions necessary to obtain the Settlement Financing in accordance with the terms of the Settlement Agreement. Prior to the consummation of the Settlement Financing, the Lazarus Parties are required to: (i) cause NPS to consummate the Settlement Financing and restrict its ability to commence a bankruptcy case, (ii) assign to NPS certain tank leases that will constitute collateral for the Settlement Financing, and (iii) cause NPS to assume joint and several liability for all or a portion of the Final Arbitration Award. The failure to achieve certain milestones in connection with obtaining the Settlement Financing will constitute an event of default under the Settlement Agreement, which would allow GEL to terminate the Settlement Agreement and enforce its rights under the Final Arbitration Award. Simultaneously with the execution of the Settlement Agreement, Jonathan Carroll and C&C entered into a Security Agreement pursuant to which Jonathan Carroll and C&C agreed to secure up to $10.0 million of LE’s obligations under the Final Arbitration Award with a security interest in their equity in LEH. The Settlement Agreement will terminate, unless extended in writing by GEL, on December 31, 2018 if the Settlement Payment is not made on or before such date, and the Settlement Agreement may be terminated by GEL following the occurrence of an event of default under the Settlement Agreement, as described above. Pursuant to the Settlement Agreement, the parties agreed to terminate the Letter Agreement, and GEL agreed not to take any action to execute or collect on the Final Arbitration Award and to take all action necessary to continue the District Court Action until the earlier of: (i) the date on which the Settlement Payment is paid or (ii) the termination of the Settlement Agreement. Blue Dolphin can provide no assurance that the conditions necessary for consummation of the Settlement will be met. If certain conditions are not met or the Settlement Agreement is terminated, GEL may seek to enforce the Final Arbitration Award against the Lazarus Parties, in which case: (i) our business operations, including crude oil and condensate procurement and our customer relationships; financial condition; and results of operations will be materially affected, and (ii) Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws. ● Veritex Secured Loan Agreement Event of Default – Veritex, as successor in interest to Sovereign Bank by merger, delivered to obligors notices of default under secured loan agreements with Veritex, stating that the Final Arbitration Award constitutes an event of default under the secured loan agreements. The occurrence of an event of default permits Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights and remedies under the secured loan agreements considering the Settlement Agreement. However, Veritex expressly reserved all of its rights, privileges and remedies related to events of default under the secured loan agreements and informed obligors that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreements. Additionally, Veritex must ultimately approve the Settlement. The debt associated with loans under secured loan agreements was classified within the current portion of long-term debt on our consolidated balance sheet at June 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet financial covenants in the secured loan agreements in the future. We can provide no assurance as to whether Veritex, as first lienholder, will approve the Settlement. If Veritex does not approve the Settlement Agreement, any exercise by Veritex of its rights and remedies under the secured loan agreements would have a material adverse effect on our business, financial condition, and results of operations, and Blue Dolphin would likely be required to seek protection under bankruptcy laws. Operating Risks For the quarter ended June 30, 2018, we reported net income of $1.8 million, or income of $0.17 per share, compared to a net loss of $25.4 million, or a loss of $2.39 per share, for the quarter ended June 30, 2017. The prior period in 2017 included the Final Arbitration Award, which was $24.3 million and represented an expense of $2.32 per share. Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.56 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis improved $0.27 between the periods, which was primarily the result of improved margins for refined petroleum products. For the six months ended June 30, 2018, we reported net income of $1.7 million, or income of $0.15 per share, compared to a net loss of $27.2 million, or a loss of $2.58 per share, for the six months ended June 30, 2017. Including the Final Arbitration Award, net income (loss) on a per share basis improved $2.73 between the periods. Excluding the Final Arbitration Award, net income (loss) on a per share basis improved $0.43 between the periods, which was primarily the result of improved margins for refined petroleum products. Execution of our business plan was hindered during the quarter ended June 30, 2018 by several factors, including: ● Working Capital Deficits – We had a working capital deficit of $69.9 million at June 30, 2018 compared to a working capital deficit of $69.5 million at December 31, 2017. Excluding the current portion of long-term debt, we had a working capital deficit of $28.7 million at June 30, 2018 compared to a working capital deficit of $30.0 million at December 31, 2017. ●· Crude Supply – We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, and other factors, as noted above. ● Financial Covenant Defaults – In addition to existing events of default related to the Final Arbitration Award, at June 30, 2018 LE and LRM were in violation of certain financial covenants in secured loan agreements with Veritex. Covenant defaults under the secured loan agreements would permit Veritex to declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing obligors’ obligations under these loan agreements, and/or exercise any other rights and remedies available. The debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at June 30, 2018 due to existing events of default related to the Final Arbitration Award as well as the uncertainty of LE and LRM’s ability to meet the financial covenants in the future. There can be no assurance that Veritex will provide a waiver of events of default related to the Final Arbitration Award, consent to the Settlement Agreement with GEL, or provide future waivers of any financial covenant defaults, which would have an adverse impact on our financial position and results of operations. We are continuing aggressive actions in 2018 to improve operations and liquidity. Management believes that it is continuing to take the appropriate steps to improve operations at the Nixon Facility and our overall financial stability. However, there can be no assurance that our business plan will be successful, that LEH and its affiliates will continue to fund our working capital needs, or that we will be able to obtain additional financing on commercially reasonable terms or at all. If Veritex does not approve the Settlement or if the Settlement Agreement with GEL is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, our business, financial condition, and results of operations will be materially adversely affected, and Blue Dolphin and its affiliates would likely be required to seek protection under bankruptcy laws. For additional disclosures related to the Final Arbitration Award, the GEL Letter Agreement, the Settlement Agreement, defaults under secured loan agreements, and risk factors that could materially affect our future business, financial condition and results of operations, refer to the following sections in this Quarterly Report: ● Part I, Item 1. Financial Statements, Notes to Consolidated Financial Statements: - Note (9) Related Party Transactions - Note (11) Long-Term Debt, Net - Note (18) Commitments and Contingencies – Legal Matters - Note (19) Subsequent Events ● Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: - Final Arbitration Award - Results of Operations - Liquidity and Capital Resources ● Part II, Item 1. Legal Proceedings ● Part II, Item 1A. Risk Factors |
2. Basis of Presentation
2. Basis of Presentation | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Basis of Presentation | The accompanying unaudited consolidated financial statements, which include Blue Dolphin and its subsidiaries, have been prepared in accordance with GAAP for interim consolidated financial information pursuant to the rules and regulations of the SEC under Article 10 of Regulation S-X and the instructions to Form 10-Q. Accordingly, certain information and footnote disclosures normally included in our audited financial statements have been condensed or omitted pursuant to the SEC’s rules and regulations. Significant intercompany transactions have been eliminated in the consolidation. In management’s opinion, all adjustments considered necessary for a fair presentation have been included, disclosures are adequate, and the presented information is not misleading. The consolidated balance sheet as of December 31, 2017 was derived from the audited financial statements at that date. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report. Operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2018, or for any other period. |
3. Significant Accounting Polic
3. Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
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 accompanying notes are representations of management who is responsible for their 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 Cash and Cash Equivalents Restricted Cash Accounts Receivable and Allowance for Doubtful Accounts Inventory Property and Equipment Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.) Intangibles – Other Debt Issue Costs Revenue Recognition We adopted the provisions of FASB ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services do not provide a material right to the customer, and such services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period. Income Taxes 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 a 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. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of June 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At June 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” for further information related to income taxes.) Impairment or Disposal of Long-Lived Assets Asset Retirement Obligations Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities assets. 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 legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and 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 for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement 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 (12) Asset Retirement Obligations” for additional information related to our AROs.) Computation of Earnings Per Share 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 that has not yet been recognized and the amount of any current and deferred tax benefit 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.) Treasury Stock New Pronouncements Adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606) New Pronouncements Issued, Not Yet Effective ASUs 2018-10 and 2016-02, Leases (Topic 842) ASU 2018-09, Codification Improvements ASU 2018-07, Compensation – Stock Compensation (Topic 718) ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity. |
4. Business Segment Information
4. Business Segment Information | 6 Months Ended |
Jun. 30, 2018 | |
Segment Reporting [Abstract] | |
Business Segment Information | We have two reportable business segments: (i) Refinery Operations and (ii) Tolling and Terminaling. Refinery operations relate to the refining and marketing of petroleum products at our 15,000-bpd crude distillation tower. Tolling and terminaling operations relate to tolling and storage terminaling services under related-party and third-party lease agreements. Both operations are conducted at the Nixon Facility. Business segment information for the periods indicated (and as of the dates indicated) was as follows: Three Months Ended June 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 88,265 $ 850 $ - $ 89,115 $ 57,337 $ - $ 57,337 Intersegment revenues - 875 - 875 - - - Less: operation costs (1) (85,761 ) (782 ) (398 ) (86,941 ) (81,055 ) (395 ) (81,450 ) EBITDA (2) $ 2,504 $ 943 $ (398 ) $ (23,718 ) $ (395 ) Depletion, depreciation and amortization (463 ) (449 ) Interest expense, net (750 ) (831 ) Income (loss) before income taxes 1,836 (25,393 ) Income tax benefit - - Net income (loss) $ 1,836 $ (25,393 ) Capital expenditures $ 487 $ 340 $ - $ 827 $ 858 $ - $ 858 Identifiable assets $ 54,966 $ 19,317 $ 964 $ 75,247 $ 71,436 $ 1,048 $ 72,484 (1) Operation costs within Refinery Operations includes related general and administrative expenses and the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. 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), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA. Six Months Ended June 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 159,777 $ 1,584 $ - $ 161,361 $ 109,942 $ - $ 109,942 Intersegment revenues - 1,546 - 1,546 - - - Less: operation costs (1) (156,676 ) (1,510 ) (842 ) (159,028 ) (136,250 ) (825 ) (137,075 ) Other non-interest income (2) - - - - - 2,216 2,216 EBITDA (3) $ 3,101 $ 1,620 $ (842 ) $ (26,308 ) $ 1,391 Depletion, depreciation and amortization (918 ) (900 ) Interest expense, net (1,493 ) (1,426 ) Income (loss) before income taxes 1,468 (27,243 ) Income tax benefit 217 - Net income (loss) $ 1,685 $ (27,243 ) Capital expenditures $ 905 $ 544 $ - $ 1,449 $ 2,889 $ - $ 2,889 Identifiable assets $ 54,966 $ 19,317 $ 964 $ 75,247 $ 71,436 $ 1,048 $ 72,484 (1) Operation costs within Refinery Operations includes related general and administrative expenses and the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. 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), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Other non-interest income reflects FLNG Land II, Inc. easement revenue. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG. (3) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA. |
5. NPS Assignment
5. NPS Assignment | 6 Months Ended |
Jun. 30, 2018 | |
Nps Assignment | |
NPS Assignment | Effective June 12, 2018, Blue Dolphin obtained 100% of the issued and outstanding membership interest of NPS, a Delaware limited liability company, from Lazarus Midstream Partners, L.P. (“Lazarus Midstream”), an affiliate of LEH, pursuant to an Assignment Agreement. The assignment of interest facilitates the Lazarus Parties exploring the possibility of obtaining the Settlement Financing under the Settlement Agreement. The assignment was accounted for as a combination of entities under common control. Accordingly, the recognized assets and liabilities of NPS were transferred at their carrying amounts at the date of transfer and the results of operations are included for the three and six months ended June 30, 2018. NPS did not have significant assets, liabilities or results of operations for the three and six months ended June 30, 2017. Assets and liabilities included in the consolidated balance sheets were $0.3 million and $0, respectively, as of June 30, 2018. NPS provides petroleum storage services at the Nixon Facility. NPS’ operations are included in our Tolling and Terminaling business segment. |
6. Prepaid Expenses and Other C
6. Prepaid Expenses and Other Current Assets | 6 Months Ended |
Jun. 30, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Prepaid Expenses and Other Current Assets | Prepaid expenses and other current assets as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Prepaid crude oil and condensate $ 1,839 $ 913 Prepaid insurance 478 294 $ 2,317 $ 1,207 |
7. Inventory
7. Inventory | 6 Months Ended |
Jun. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Inventory | Inventory as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) AGO $ 1,945 $ 213 Crude oil and condensate 1,573 961 Naphtha 417 170 Chemicals 224 162 Propane 16 17 LPG mix 5 8 HOBM - 1,558 $ 4,180 $ 3,089 |
8. Property, Plant and Equipmen
8. Property, Plant and Equipment, Net | 6 Months Ended |
Jun. 30, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment, Net | Property, plant and equipment, net, as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Refinery and facilities $ 54,114 $ 51,432 Land 566 566 Other property and equipment 747 653 55,427 52,651 Less: Accumulated depletion, depreciation, and amortization (9,414 ) (8,495 ) 46,013 44,156 Construction in progress 18,979 20,441 $ 64,992 $ 64,597 We capitalize interest cost incurred on funds used to construct property, plant, and equipment. Capitalized interest, which is recorded as part of the asset to which it relates, is depreciated over the asset’s useful life. Interest cost capitalized, which is currently included in construction in progress, was $3.7 million and $3.9 million at June 30, 2018 and December 31, 2017, respectively. We expect construction of petroleum storage tanks at the Nixon Facility to continue until year end. |
9. Related Party Transactions
9. Related Party Transactions | 6 Months Ended |
Jun. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Blue Dolphin and certain of its subsidiaries are party to several agreements with LEH and its affiliates. Management believes that these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. Related Parties LEH Ingleside Crude, LLC (“Ingleside”) Lazarus Marine Terminal I, LLC (“LMT”) Jonathan Carroll Currently, we depend on LEH and its affiliates (including Jonathan Carroll and Ingleside) for financing when revenue from operations and borrowings under bank facilities are insufficient to meet our liquidity needs. Such borrowings are reflected in our consolidated balance sheets in accounts payable, related party, and/or long-term debt, related party. Operations Related Agreements . Amended and Restated Operating Agreement Jet Fuel Sales Agreement Terminal Services Agreement Amended and Restated Tank Lease Agreement Dock Tolling Agreement Financial Agreements . BDPL Loan Agreement The proceeds of the BDPL Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain property owned by BDPL. Outstanding principal owed to LEH under the BDPL Loan Agreement is reflected in long-term debt, related party, current portion in our consolidated balance sheets. Accrued interest under the BDPL Loan Agreement is reflected in interest payable, related party, current portion in our consolidated balance sheets. Promissory Notes ● June LEH Note ● March Ingleside Note ● March Carroll Note Debt Assumption Agreement Amended and Restated Guaranty Fee Agreements Financial Statements Impact Consolidated Balance Sheets Long-term debt, related party associated with the BDPL Loan Agreement, March Ingleside Note, and the March Carroll Note as of the dates indicated was as follows: June 30, December 31, 2018 2017 (in thousands) LEH $ 4,036 $ 4,000 Ingleside 1,238 1,169 Jonathan Carroll 786 439 6,060 5,608 Less: Long-term debt, related party, current portion (6,060 ) (4,000 ) $ - $ 1,608 Accrued interest associated with the BDPL Loan Agreement was $1.2 million and $0.9 million at June 30, 2018 and December 31, 2017, respectively. Consolidated Statements of Operations Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except percent amounts) LEH Jet fuel product sales $ 25,549 28.7 % $ 20,158 35.2 % $ 46,116 28.6 % $ 35,558 32.3 % HOBM sales - 0.0 % - 0.0 % - 0.0 % 3,657 3.3 % Jet fuel storage fees - 0.0 % 375 0.6 % - 0.0 % 750 0.7 % Other customers 0.0 % Product sales 62,716 70.4 % 36,475 63.6 % 113,661 70.4 % 69,320 63.1 % Tolling and terminaling 850 0.9 % 329 0.6 % 1,584 1.0 % 657 0.6 % $ 89,115 100.0 % $ 57,337 100.0 % $ 161,361 100.0 % $ 109,942 100.0 % Related party cost of goods sold associated with the Dock Tolling Agreement with LMT totaled $0.2 million for both the three months ended June 30, 2018 and 2017. Related party cost of goods sold associated with the Dock Tolling Agreement with LMT totaled $0.4 million for both the six months ended June 30, 2018 and 2017. Related party refinery operating expenses associated with the Amended and Restated Operating Agreement with LEH for the periods indicated were as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Operating Operating Operating Operating Expense Expense Expense Expense Amount per bbl Amount per bbl Amount per bbl Amount per bbl (in thousands, except per bbl amounts) LEH $ 1,377 $ 1.16 $ 1,652 $ 153 $ 3,299 $ 1.51 $ 4,465 $ 2.14 $ 1,377 $ 1.16 $ 1,652 $ 1.53 $ 3,299 $ 1.51 $ 4,465 $ 2.14 For the three months ended June 30, 2018, refinery operating expenses decreased approximately $0.3 million, or $0.37 per bbl, compared to the same period a year earlier. For the six months ended June 30, 2018, refinery operating expenses decreased approximately $1.2 million, or $0.63 per bbl, compared to the same six-month period a year earlier. The decrease in refinery operating expenses was due to the revised cost-plus expense reimbursement structure under the Amended and Restated Operating Agreement, as well as management’s efforts to reduce spending. Related party interest expense associated with the BDPL Loan Agreement, the Restated Guaranty Fee Agreements, and the related-party promissory notes (the June LEH Note, the March Ingleside Note, and March Carroll Note) for the periods indicated was as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) Jonathan Carroll $ 177 $ 166 $ 340 $ 334 LEH 163 211 323 396 Ingleside 24 23 71 46 $ 364 $ 400 $ 734 $ 776 |
10. Accrued Expenses and Other
10. Accrued Expenses and Other Current Liabilities | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure Text Block Supplement [Abstract] | |
Accrued Expenses and Other Current Liabilities | Accrued expenses and other current liabilities as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Unearned revenue $ 2,721 $ 450 Board of director fees payable 241 207 Other payable 213 116 Customer deposits 109 109 Property taxes 81 131 Excise and income taxes payable 78 79 Insurance 44 68 $ 3,487 $ 1,160 |
11. Long-Term Debt, Net
11. Long-Term Debt, Net | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt, Net | Long-term debt, net represents the outstanding principal of long-term debt less associated debt issue costs. Long-term debt, net as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 22,841 $ 23,199 Second Term Loan Due 2034 (in default) 9,404 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 62 - $ 37,285 $ 37,679 Less: Current portion of long-term debt, net (35,194 ) (35,544 ) Less: Unamortized debt issue costs (2,070 ) (2,135 ) $ 21 $ - Unamortized debt issue costs, which relate to secured loan agreements with Veritex, as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 1,674 $ 1,674 Second Term Loan Due 2034 (in default) 768 768 Less: Accumulated amortization (372 ) (307 ) $ 2,070 $ 2,135 Amortization expense was $0.03 million for both the three months ended June 30, 2018 and 2017. Amortization expense was $0.6 million for both the six months ended June 30, 2018 and 2017. Accrued interest associated with long-term debt, net is reflected as interest payable, in default and interest payable, related party, in default in our consolidated balance sheets. Accrued interest as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,444 $ 2,046 BDPL Loan Agreement (related party) 1,214 892 Second Term Loan Due 2034 (in default) 49 49 First Term Loan Due 2034 (in default) 36 40 3,743 3,027 Less: Interest payable, current portion (3,743 ) (3,027 ) Long-term interest payable, net of current portion $ - $ - Related Party First Term Loan Due 2034 (In Default) a term loan in the principal amount of $25.0 million As described elsewhere in this Quarterly Report, Veritex notified LE that the Final Arbitration Award constitutes an event of default under the First Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at June 30, 2018, LE was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the first Term Loan Due 2034. LE also failed to replenish a payment reserve account as required. The occurrence of events of default under the First Term Loan Due 2034 permits Veritex to declare the amounts owed under the First Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LE’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the First Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the First Term Loan Due 2034 and informed LE that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the First Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the First Term Loan Due 2034, Jonathan Carroll was required to guarantee r epayment A portion of the proceeds of the First Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed under a previous debt facility with American First National Bank. Remaining proceeds are being used primarily to construct new petroleum storage tanks at the Nixon Facility. The First Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a payment reserve account held by Veritex, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan Carroll. The First Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Second Term Loan Due 2034 (In Default) As described elsewhere in this Quarterly Report, Veritex notified LRM that the Final Arbitration Award constitutes an event of default under the Second Term Loan Due 2034. In addition to existing events of default related to the Final Arbitration Award, at June 30, 2018, LRM was in violation of the debt service coverage ratio, the current ratio, and debt to net worth ratio financial covenants related to the Second Term Loan Due 2034. The occurrence of events of default under the Second Term Loan Due 2034 permits Veritex to declare the amounts owed under the Second Term Loan Due 2034 immediately due and payable, exercise its rights with respect to collateral securing LRM’s obligations under the loan agreement, and/or exercise any other rights and remedies available. Veritex informed obligors that it is not currently exercising its rights, privileges and remedies under the Second Term Loan Due 2034 considering the Settlement Agreement. However, Veritex expressly reserved all its rights, privileges and remedies related to events of default under the Second Term Loan Due 2034 and informed LRM that it would consider a final confirmation of the Final Arbitration Award to be a material event of default under the loan agreement. Additionally, Veritex must ultimately approve the Settlement. Any exercise by Veritex of its rights and remedies under the Second Term Loan Due 2034 would have a material adverse effect on our business, financial condition, and results of operations and would likely require Blue Dolphin to seek protection under bankruptcy laws. (See “Note (1) Organization – Going Concern and Operating Risks” for additional disclosures related to the First Term Loan Due 2034, the Final Arbitration Award and financial covenant violations.) As a condition of the Second Term Loan Due 2034, Jonathan Carroll was required to guarantee repayment of funds borrowed and interest accrued under the loan. For his personal guarantee, LRM entered a Guaranty Fee Agreement with Jonathan Carroll whereby he earns a fee equal to 2.00% per annum of the outstanding principal balance owed under the Second Term Loan Due 2034. Effective in April 2017, the Guaranty Fee Agreement associated with the Second Term Loan Due 2034 was amended and restated to reflect payment in cash and shares of Blue Dolphin Common Stock. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.1 million for both the three months ended June 30, 2018 and 2017. Guaranty fees earned by Jonathan Carroll related to the Second Term Loan Due 2034 totaled $0.2 million for both the six months ended June 30, 2018 and 2017. Guaranty fees are recognized monthly as incurred and are included in interest and other expense in our consolidated statements of operations. LEH, LE and Blue Dolphin also guaranteed the Second Term Loan Due 2034. (See “Note (9) Related Party Transactions” for additional disclosures related to LEH and Jonathan Carroll.) A portion of the proceeds of the Second Term Loan Due 2034 were used to refinance a previous bridge loan from Veritex in the amount of $3.0 million. Remaining proceeds are being used primarily to construct additional new petroleum storage tanks at the Nixon Facility. The Second Term Loan Due 2034 is secured by: (i) a second priority lien on the rights of LE in the crude distillation tower and the other collateral of LE pursuant to a security agreement; (ii) a first priority lien on the real property interests of LRM; (iii) a first priority lien on all of LRM’s fixtures, furniture, machinery and equipment; (iv) a first priority lien on all of LRM’s contractual rights, general intangibles and instruments, except with respect to LRM’s rights in its leases of certain specified tanks, with respect to which Veritex has a second priority lien in such leases subordinate to a prior lien granted by LRM to Veritex to secure obligations of LRM under the Term Loan Due 2017; and (v) all other collateral as described in the security documents. The Second Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for bank facilities of this type. Notre Dame Debt (In Default) The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the crude distillation tower and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Capital Leases Boiler Equipment Lease Crane Lease A summary of equipment held under long-term capital leases as of the dates indicated follows: June 30, December 31, 2018 2017 (in thousands) Crane $ 94 $ - Less: accumulated depreciation (7 ) - $ 87 $ - |
12. Asset Retirement Obligation
12. Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Refinery and Facilities Pipelines and Facilities and Oil and Gas Properties Changes to our ARO liability for the periods indicated were as follows: June 30, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 143 287 2,458 2,315 Less: asset retirement obligations, current portion (2,458 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ - $ - |
13. Treasury Stock
13. Treasury Stock | 6 Months Ended |
Jun. 30, 2018 | |
Equity [Abstract] | |
Treasury Stock | At June 30, 2018 and December 31, 2017, we had 0 shares of treasury stock. In May 2017, we issued 150,000 shares of treasury stock to Jonathan Carroll as payment for amounts due under the March Carroll Note. The issuance price of the treasury stock issued to Mr. Carroll was $2.48 per share, which represents the preceding 30-day average closing price of the Common Stock, in accordance with the Amended and Restated Guaranty Fee Agreements. The shares of treasury stock issued to Mr. Carroll are restricted per applicable securities holding periods for affiliates. |
14. Concentration of Risk
14. Concentration of Risk | 6 Months Ended |
Jun. 30, 2018 | |
Risks and Uncertainties [Abstract] | |
Concentration of Risk | Bank Accounts Key Supplier We currently have in place a month-to-month evergreen crude supply contract with a major integrated oil and gas company. This supplier currently provides us with adequate amounts of crude oil and condensate, and we expect the supplier to continue to do so for the foreseeable future. However, our ability to purchase adequate amounts of crude oil and condensate is dependent on our liquidity and access to capital, which could be adversely affected if the Settlement Agreement is terminated and GEL seeks to confirm and enforce the Final Arbitration Award, as well as other factors, including as net losses, working capital deficits, and financial covenant defaults in secured loan agreements. Significant Customers For the three months ended June 30, 2018, we had 5 customers that accounted for approximately 96.7% of refinery operations revenue. LEH, a related party, was 1 of these 5 significant customers and accounted for approximately 28.9% of refinery operations revenue. At June 30, 2018, these 5 customers represented approximately $0.7 million in accounts receivable. LEH represented approximately $0 in accounts receivable. LEH purchases our jet fuel and resells the jet fuel to a government agency. LEH bids for jet fuel contracts are evaluated under preferential pricing terms due to its HUBZone certification. (See “Note (9) Related Party Transactions,” “Note (11) Long-Term Debt, Net,” and “Note (18) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH.) For the three months ended June 30, 2017, we had 4 customers that accounted for approximately 80.5% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 35.6% of our refined petroleum product sales. At June 30, 2017, these 4 customers represented approximately $0.3 million in accounts receivable. LEH represented approximately $0 in accounts receivable. For the six months ended June 30, 2018, we had 4 customers that accounted for approximately 86.8% of our refined petroleum product sales. LEH was 1 of these 4 significant customers and accounted for approximately 28.9% of our refined petroleum product sales. At June 30, 2018, these 4 customers represented approximately $0.7 million in accounts receivable. LEH represented approximately $0 in accounts receivable. For the six months ended June 30, 2017, we had 3 customers that accounted for approximately 75.6% of our refined petroleum product sales. LEH was 1 of these 3 significant customers and accounted for approximately 35.9% of our refined petroleum product sales. At June 30, 2017, these 3 customers represented approximately $0.1 million in accounts receivable. LEH represented approximately $0 in accounts receivable. Refined Petroleum Product Sales Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) LPG mix $ - 0.0 % $ - 0.0 % $ 3 0.0 % $ 121 0.1 % Naphtha 23,648 26.8 % 13,254 23.4 % 39,966 25.0 % 27,017 24.9 % Jet fuel 25,549 28.9 % 20,158 35.6 % 46,116 28.9 % 35,558 32.8 % HOBM 22,430 25.4 % 10,883 19.2 % 38,859 24.3 % 21,569 19.9 % AGO 16,638 18.9 % 12,338 21.8 % 34,833 21.8 % 24,270 22.3 % $ 88,265 100.0 % $ 56,633 100.0 % $ 159,777 100.0 % $ 108,535 100.0 % |
15. Leases
15. Leases | 6 Months Ended |
Jun. 30, 2018 | |
Leases, Operating [Abstract] | |
Leases | BDSC leases our principal office space in Houston, Texas under a 2006 lease agreement. Effective January 1, 2018, BDSC entered an amended lease agreement (the “Lease Amendment”) that extended the lease period by sixty-eight (68) months expiring on August 31, 2023. Under the Lease Amendment, our base rent for 6,489 square feet is $0.01 million per month. The Lease Amendment includes an allowance for lessee improvements, rent abatements, and a five-year renewal option. For the three months ended June 30, 2018 and 2017, rent expense totaled $0.06 million and $0.05 million, respectively. For the six months ended June 30, 2018 and 2017, rent expense totaled $0.11 million and $0.13 million, respectively. Rent expense is recognized on a straight-line basis. |
16. Income Taxes
16. Income Taxes | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. The principal element of the Tax Cuts and Jobs Act relevant to our financial statements is a reduction in the U.S. federal corporate tax rate from 34% to 21%, effective January 1, 2018. Other provisions of the Tax Cuts and Jobs Act did not have a significant impact on our financial statements for the three and six months ended June 30, 2018. For the three months ended June 30, 2018 and 2017, we recognized an income tax benefit of $0. For the six months ended June 30, 2018 and 2017, we recognized an income tax benefit of $0.2 million and $0, respectively. The provision for income tax benefit (expense) as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Current $ 108 $ - Deferred Impact of change in enacted tax rates - (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 217 $ - In 2018, our effective tax rate differed from the U.S. federal statutory rate primarily due to Alternative Minimum Tax credits made refundable by the Tax Cuts and Jobs Act. In 2017, our effective tax rate differed from the U.S. federal statutory rate primarily due to re-measuring deferred income taxes at the new statutory tax rate and the related change of the valuation allowance over our deferred tax assets. At the date of enactment of the Tax Cuts and Jobs Act, we re-measured our deferred tax assets and liabilities using a rate of 21%, which is the rate expected to be in place when such deferred assets and liabilities are expected to reverse in the future. The re-measurement, which was offset by a change in our valuation allowance, reduced our net deferred tax assets by approximately $6.7 million. The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin. Although TMT is imposed on an entity’s gross profit rather than on its net income, certain aspects of TMT make it like an income tax. Accordingly, TMT is treated as an income tax for financial reporting purposes. For the three and six months ended June 30, 2018 and 2017, we recognized a provision for state income tax of $0. Deferred income taxes as of the dates indicated consisted of the following: June 30, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,641 $ 9,767 Accrued arbitration award payable 3,180 4,122 Start-up costs (crude oil and condensate processing facility) 721 763 Asset retirement obligations liability/deferred revenue 520 495 AMT credit and other 100 217 Total deferred tax assets 15,162 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,764 ) (4,415 ) Total deferred tax liabilities (4,764 ) (4,415 ) 10,398 10,950 Valuation allowance (10,290 ) (10,950 ) Deferred tax assets, net $ 108 $ - Deferred Income Taxes NOL Carryforwards NOL carryforwards that remained available for future use for the periods indicated were as follow (amounts shown are net of NOLs that will expire unused because of the IRC Section 382 limitation): Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses - 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses - 4,160 4,160 Balance at June 30, 2018 $ 9,614 $ 34,378 $ 43,992 Valuation Allowance |
17. Earnings Per Share
17. Earnings Per Share | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | A reconciliation between basic and diluted income per share for the periods indicated was as follows: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except share and per share amounts) Net income (loss) $ 1,836 $ (25,393 ) $ 1,685 $ (27,243 ) Basic and diluted income (loss) per share $ 0.17 $ (2.39 ) $ 0.15 $ (2.58 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,637,101 10,925,513 10,556,356 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 and six months ended June 30, 2018 and 2017 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding. |
18. Commitments and Contingenci
18. Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Legal Matters Final Arbitration Award and Settlement Agreement Veritex Secured Loan Agreement Event of Default Other Legal Matters Amended and Restated Operating Agreement FLNG Easements Financing Agreements Guarantees Health, Safety and Environmental Matters Nixon Facility Expansion Supplemental Pipeline Bonds There can be no assurance that BOEM will: (i) accept a proposal for a reduced amount of supplemental financial assurance, (ii) not require additional supplemental pipeline bonds related to BDPL’s existing pipeline rights-of-way, and/or (iii) not impose penalties under the INCs. If BDPL is required by BOEM to provide significant additional supplemental bonds or acceptable financial assurance or is assessed significant penalties under the INCs, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. As of June 30, 2018 and December 31, 2017, BDPL maintained approximately $0.9 million in credit and cash-backed pipeline rights-of-way bonds issued to the BOEM. |
19. Subsequent Events
19. Subsequent Events | 6 Months Ended |
Jun. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | Settlement Agreement |
3. Significant Accounting Pol25
3. Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Use of Estimates | We have made several 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. We believe our current estimates are reasonable and appropriate, however, 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. |
Restricted Cash | Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Veritex attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Veritex as security for payments under a loan agreement, and (iii) a construction contingency account under which Veritex will fund contingencies. Restricted cash, noncurrent represents funds held in the Veritex disbursement account for payment of future construction related expenses to build new petroleum storage tanks. |
Accounts Receivable and Allowance for Doubtful Accounts | Our accounts receivable consists of customer obligations due in the ordinary course of business. Since we have a small number of customers with individually large amounts due on any given date, we evaluate potential and existing customers’ financial condition, credit worthiness, and payment history to minimize credit risk. Allowance for doubtful accounts is based on a combination of current sales and specific identification methods. If necessary, we establish an allowance for doubtful accounts to estimate the amount of probable credit losses. Allowance for doubtful accounts totaled $0.1 million and $0 at June 30, 2018 and December 31, 2017, respectively. |
Inventory | Our inventory primarily consists of refined petroleum products, crude oil and condensate, and chemicals. Inventory is valued at lower of cost or net realizable value with cost being determined by the average cost method, and net realizable value being determined based on estimated selling prices less any associated delivery costs. If the net realizable value of our refined petroleum products inventory declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See “Note (7) Inventory” for additional disclosures related to our inventory.) |
Property and Equipment | Refinery and Facilities We record refinery and facilities at cost less any adjustments for depreciation or impairment. Adjustment of the asset and the related accumulated depreciation accounts are made for the refinery and facilities asset’s retirement and disposal, with the resulting gain or loss included in the consolidated statements of operations. For financial reporting purposes, depreciation of refinery and facilities assets is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities assets are placed in service. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. Pipelines and Facilities Oil and Gas Properties Construction in Progress (See “Note (8) Property, Plant and Equipment, Net” for additional disclosures related to our refinery and facilities assets, oil and gas properties, pipelines and facilities assets, and construction in progress.) |
Intangibles - Other | Trade name, an intangible asset, represents the “Blue Dolphin Energy Company” brand name. We account for intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we determined trade name to have an indefinite useful life, and 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 2017. Upon completion of that testing, our trade name asset was fully impaired at December 31, 2017. |
Debt Issue Costs | We have debt issue costs related to certain refinery and facilities assets 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. Debt issue costs are presented net with the related debt liability. (See “Note (11) Long-Term Debt, Net” for additional disclosures related to debt issue costs.) |
Revenue Recognition | We adopted the provisions of FASB ASU 2014-09, Revenue from Contracts with Customers (ASC 606) Refinery Operations Revenue Tolling and Terminaling Revenue Revenue from tank storage customers may, from time to time, include fees for ancillary services, such as in-tank and tank-to-tank blending. These services are considered optional to the customer, and the price we charge for such services is not included in the fixed cost under the customer’s tank storage agreement. Ancillary services do not provide a material right to the customer, and such services are considered a separate performance obligation by us under the tank storage agreement. The performance obligation is satisfied when the requested service has been performed in the applicable period. |
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 reporting period 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 a 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. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2017. Such objective evidence limits the ability to consider other subjective evidence, such as our projections for future growth. Based on this evaluation, we recorded a valuation allowance against the deferred tax assets for which realization was not deemed more likely than not as of June 30, 2018 and December 31, 2017. We expect to recover deferred tax assets related to the Alternative Minimum Tax (“AMT”). The benefit of an uncertain tax position is recognized in the financial statements if it meets a minimum recognition threshold. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more-likely-than-not criteria, the benefit recorded in the financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. At June 30, 2018 and December 31, 2017, there were no uncertain tax positions for which a reserve or liability was necessary. (See “Note (16) Income Taxes” 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 periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. 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. As a result of the Final Arbitration Award, which represents a significant adverse change that could affect the value of a long-lived asset, management performed potential impairment testing of our refinery and facilities assets in the fourth quarter of 2017. Upon completion of that testing, we determined that no impairment was necessary at December 31, 2017. We did not record any impairment of our refinery and facilities assets for the periods presented. |
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 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 assets. 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 legal or contractual obligation to dismantle or remove the refinery and facilities assets arises and 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 for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement 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 (12) Asset Retirement Obligations” 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 consolidated statements of operations and requires a reconciliation of the denominator 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 that has not yet been recognized and the amount of any current and deferred tax benefit 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.) |
Treasury Stock | We accounted for treasury stock under the cost method. In May 2017, our treasury stock was re-issued. The net change in share price after acquisition of the treasury stock was 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.) |
New Pronouncements Adopted | The FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. Recently adopted ASUs include: ASU 2014-09, Revenue from Contracts with Customers (ASC 606) |
New Pronouncements Issued but Not Yet Effective | The following are recently issued, but not yet effective, ASU’s that may influence our consolidated financial position, results of operations, or cash flows: ASUs 2018-10 and 2016-02, Leases (Topic 842) ASU 2018-09, Codification Improvements ASU 2018-07, Compensation – Stock Compensation (Topic 718) ASU 2018-05, Income Taxes (Topic 740) Other new pronouncements issued but not yet effective are not expected to have a material impact on our financial position, results of operations, or liquidity. |
4. Business Segment Informati26
4. Business Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Segment Reporting [Abstract] | |
Business segment reporting | Three Months Ended June 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 88,265 $ 850 $ - $ 89,115 $ 57,337 $ - $ 57,337 Intersegment revenues - 875 - 875 - - - Less: operation costs (1) (85,761 ) (782 ) (398 ) (86,941 ) (81,055 ) (395 ) (81,450 ) EBITDA (2) $ 2,504 $ 943 $ (398 ) $ (23,718 ) $ (395 ) Depletion, depreciation and amortization (463 ) (449 ) Interest expense, net (750 ) (831 ) Income (loss) before income taxes 1,836 (25,393 ) Income tax benefit - - Net income (loss) $ 1,836 $ (25,393 ) Capital expenditures $ 487 $ 340 $ - $ 827 $ 858 $ - $ 858 Identifiable assets $ 54,966 $ 19,317 $ 964 $ 75,247 $ 71,436 $ 1,048 $ 72,484 (1) Operation costs within Refinery Operations includes related general and administrative expenses and the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. 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), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA. Six Months Ended June 30, 2018 2017 (in thousands) Segments Segment Refinery Tolling and Corporate Refinery Corporate Operations Terminaling & Other Total Operations & Other Total Revenues from external customers $ 159,777 $ 1,584 $ - $ 161,361 $ 109,942 $ - $ 109,942 Intersegment revenues - 1,546 - 1,546 - - - Less: operation costs (1) (156,676 ) (1,510 ) (842 ) (159,028 ) (136,250 ) (825 ) (137,075 ) Other non-interest income (2) - - - - - 2,216 2,216 EBITDA (3) $ 3,101 $ 1,620 $ (842 ) $ (26,308 ) $ 1,391 Depletion, depreciation and amortization (918 ) (900 ) Interest expense, net (1,493 ) (1,426 ) Income (loss) before income taxes 1,468 (27,243 ) Income tax benefit 217 - Net income (loss) $ 1,685 $ (27,243 ) Capital expenditures $ 905 $ 544 $ - $ 1,449 $ 2,889 $ - $ 2,889 Identifiable assets $ 54,966 $ 19,317 $ 964 $ 75,247 $ 71,436 $ 1,048 $ 72,484 (1) Operation costs within Refinery Operations includes related general and administrative expenses and the arbitration award and associated fees. Operation cost within Tolling and Terminaling includes an allocation of refinery operating expenses and other costs (e.g. insurance and maintenance), as well as associated refinery fuel costs. 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), as well as expenses associated with our pipeline assets and oil and gas leasehold interests (such as accretion). (2) Other non-interest income reflects FLNG Land II, Inc. easement revenue. See “Note (18) Commitments and Contingencies – FLNG Easements” for further discussion related to FLNG. (3) EBITDA is a non-GAAP financial measure. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Non-GAAP Financial Measures” for additional information related to EBITDA. |
6. Prepaid Expenses and Other27
6. Prepaid Expenses and Other Current Assets (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Prepaid balances | June 30, December 31, 2018 2017 (in thousands) Prepaid crude oil and condensate $ 1,839 $ 913 Prepaid insurance 478 294 $ 2,317 $ 1,207 |
7. Inventory (Tables)
7. Inventory (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Inventory | June 30, December 31, 2018 2017 (in thousands) AGO $ 1,945 $ 213 Crude oil and condensate 1,573 961 Naphtha 417 170 Chemicals 224 162 Propane 16 17 LPG mix 5 8 HOBM - 1,558 $ 4,180 $ 3,089 |
8. Property, Plant and Equipm29
8. Property, Plant and Equipment, Net (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property and equipment | June 30, December 31, 2018 2017 (in thousands) Refinery and facilities $ 54,114 $ 51,432 Land 566 566 Other property and equipment 747 653 55,427 52,651 Less: Accumulated depletion, depreciation, and amortization (9,414 ) (8,495 ) 46,013 44,156 Construction in progress 18,979 20,441 $ 64,992 $ 64,597 |
9. Related Party Transactions (
9. Related Party Transactions (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Related Party Transactions [Abstract] | |
Accounts Payable, Related Party | June 30, December 31, 2018 2017 (in thousands) LEH $ 4,036 $ 4,000 Ingleside 1,238 1,169 Jonathan Carroll 786 439 6,060 5,608 Less: Long-term debt, related party, current portion (6,060 ) (4,000 ) $ - $ 1,608 |
Accrued interest Expenses | Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except percent amounts) LEH Jet fuel product sales $ 25,549 28.7 % $ 20,158 35.2 % $ 46,116 28.6 % $ 35,558 32.3 % HOBM sales - 0.0 % - 0.0 % - 0.0 % 3,657 3.3 % Jet fuel storage fees - 0.0 % 375 0.6 % - 0.0 % 750 0.7 % Other customers 0.0 % Product sales 62,716 70.4 % 36,475 63.6 % 113,661 70.4 % 69,320 63.1 % Tolling and terminaling 850 0.9 % 329 0.6 % 1,584 1.0 % 657 0.6 % $ 89,115 100.0 % $ 57,337 100.0 % $ 161,361 100.0 % $ 109,942 100.0 % |
Refinery operating expenses | Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Operating Operating Operating Operating Expense Expense Expense Expense Amount per bbl Amount per bbl Amount per bbl Amount per bbl (in thousands, except per bbl amounts) LEH $ 1,377 $ 1.16 $ 1,652 $ 153 $ 3,299 $ 1.51 $ 4,465 $ 2.14 $ 1,377 $ 1.16 $ 1,652 $ 1.53 $ 3,299 $ 1.51 $ 4,465 $ 2.14 Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) Jonathan Carroll $ 177 $ 166 $ 340 $ 334 LEH 163 211 323 396 Ingleside 24 23 71 46 $ 364 $ 400 $ 734 $ 776 |
10. Accrued Expenses and Othe31
10. Accrued Expenses and Other Current Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure Text Block Supplement [Abstract] | |
Accrued expenses and other current liabilities | June 30, December 31, 2018 2017 (in thousands) Unearned revenue $ 2,721 $ 450 Board of director fees payable 241 207 Other payable 213 116 Customer deposits 109 109 Property taxes 81 131 Excise and income taxes payable 78 79 Insurance 44 68 $ 3,487 $ 1,160 |
11. Long-Term Debt, Net (Tables
11. Long-Term Debt, Net (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long Term Debt | June 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 22,841 $ 23,199 Second Term Loan Due 2034 (in default) 9,404 9,502 Notre Dame Debt (in default) 4,978 4,978 Capital leases 62 - $ 37,285 $ 37,679 Less: Current portion of long-term debt, net (35,194 ) (35,544 ) Less: Unamortized debt issue costs (2,070 ) (2,135 ) $ 21 $ - |
Schedule of Debt issue costs | June 30, December 31, 2018 2017 (in thousands) First Term Loan Due 2034 (in default) $ 1,674 $ 1,674 Second Term Loan Due 2034 (in default) 768 768 Less: Accumulated amortization (372 ) (307 ) $ 2,070 $ 2,135 |
Accrued interest related to our long-term debt, net | June 30, December 31, 2018 2017 (in thousands) Notre Dame Debt (in default) $ 2,444 $ 2,046 BDPL Loan Agreement (related party) 1,214 892 Second Term Loan Due 2034 (in default) 49 49 First Term Loan Due 2034 (in default) 36 40 3,743 3,027 Less: Interest payable, current portion (3,743 ) (3,027 ) Long-term interest payable, net of current portion $ - $ - |
Schedule of summary of equipment held under long-term capital leases | June 30, December 31, 2018 2017 (in thousands) Crane $ 94 $ - Less: accumulated depreciation (7 ) - $ 87 $ - |
12. Asset Retirement Obligati33
12. Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | June 30, December 31, 2018 2017 (in thousands) Asset retirement obligations, at the beginning of the period $ 2,315 $ 2,028 Accretion expense 143 287 2,458 2,315 Less: asset retirement obligations, current portion (2,458 ) (2,315 ) Long-term asset retirement obligations, at the end of the period $ - $ - |
14. Concentration of Risk (Tabl
14. Concentration of Risk (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Risks and Uncertainties [Abstract] | |
Percentages of all refined petroleum products sales to total sales | Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) LPG mix $ - 0.0 % $ - 0.0 % $ 3 0.0 % $ 121 0.1 % Naphtha 23,648 26.8 % 13,254 23.4 % 39,966 25.0 % 27,017 24.9 % Jet fuel 25,549 28.9 % 20,158 35.6 % 46,116 28.9 % 35,558 32.8 % HOBM 22,430 25.4 % 10,883 19.2 % 38,859 24.3 % 21,569 19.9 % AGO 16,638 18.9 % 12,338 21.8 % 34,833 21.8 % 24,270 22.3 % $ 88,265 100.0 % $ 56,633 100.0 % $ 159,777 100.0 % $ 108,535 100.0 % |
16. Income Taxes (Tables)
16. Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income tax benefit (expense) | June 30, December 31, 2018 2017 (in thousands) Current $ 108 $ - Deferred Impact of change in enacted tax rates - (6,654 ) Change in valuation allowance 109 6,654 Total provision for income taxes $ 217 $ - |
Deferred tax assets and deferred tax liabilities | June 30, December 31, 2018 2017 (in thousands) Deferred tax assets: Net operating loss and capital loss carryforwards $ 10,641 $ 9,767 Accrued arbitration award payable 3,180 4,122 Start-up costs (crude oil and condensate processing facility) 721 763 Asset retirement obligations liability/deferred revenue 520 495 AMT credit and other 100 217 Total deferred tax assets 15,162 15,365 Deferred tax liabilities: Basis differences in property and equipment (4,764 ) (4,415 ) Total deferred tax liabilities (4,764 ) (4,415 ) 10,398 10,950 Valuation allowance (10,290 ) (10,950 ) Deferred tax assets, net $ 108 $ - |
NOL carryforwards | Net Operating Loss Carryforward Pre-Ownership Change Post-Ownership Change Total (in thousands) Balance at December 31, 2016 $ 9,614 $ 23,562 $ 33,176 Net operating losses - 6,656 6,656 Balance at December 31, 2017 $ 9,614 $ 30,218 $ 39,832 Net operating losses - 4,160 4,160 Balance at June 30, 2018 $ 9,614 $ 34,378 $ 43,992 |
17. Earnings Per Share (Tables)
17. Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings per share | Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (in thousands, except share and per share amounts) Net income (loss) $ 1,836 $ (25,393 ) $ 1,685 $ (27,243 ) Basic and diluted income (loss) per share $ 0.17 $ (2.39 ) $ 0.15 $ (2.58 ) Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,925,513 10,637,101 10,925,513 10,556,356 |
1. Organization (Details Narrat
1. Organization (Details Narrative) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||
Net income (loss) | $ 1,836 | $ (25,393) | $ 1,685 | $ (27,243) | |
Net Loss per common share | $ 0.17 | $ (2.39) | $ 0.15 | $ (2.58) | |
Working capital deficit current portion | $ (69,900) | $ (69,900) | $ (69,500) | ||
Working capital deficit payment of Operations | $ (28,700) | $ (28,700) | $ (30,000) |
3. Significant Accounting Pol38
3. Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Accounting Policies [Abstract] | |||||
Restricted cash (current portion) | $ 49 | $ 49 | $ 49 | ||
Restricted cash, noncurrent | 1,602 | 1,602 | 1,602 | ||
Allowance for doubtful accounts | 100 | 100 | $ 0 | ||
Gain on the disposal of property | $ 0 | $ 0 | $ 0 | $ 1,834 |
4. Business Segment Informati39
4. Business Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Revenue from operations | $ 89,115 | $ 57,337 | $ 161,361 | $ 109,942 | |
Depletion, depreciation and amortization | (30) | (30) | (60) | (60) | |
Income tax benefit | 108 | $ 0 | |||
Net income (loss) | 1,836 | (25,393) | 1,685 | (27,243) | |
Refinery Operations [Member] | |||||
Revenue from operations | 88,265 | 57,337 | 159,777 | 109,942 | |
Intersegment revenues | 0 | 0 | 0 | 0 | |
Less: cost of operations | (85,761) | (81,055) | (156,676) | (136,250) | |
Other non-interest income | 0 | 0 | |||
EBITDA | 2,504 | (23,718) | 3,101 | (26,308) | |
Capital expenditures | 487 | 858 | 905 | 2,889 | |
Identifiable assets | 54,966 | 71,436 | 54,966 | 71,436 | |
Tolling and Terminaling [Member] | |||||
Revenue from operations | 850 | 1,584 | |||
Intersegment revenues | 875 | 1,546 | |||
Less: cost of operations | (782) | (1,510) | |||
Other non-interest income | 0 | ||||
EBITDA | 943 | 1,620 | |||
Capital expenditures | 340 | 544 | |||
Identifiable assets | 19,317 | 19,317 | |||
Corporate & Other [Member] | |||||
Revenue from operations | 0 | 0 | 0 | 0 | |
Intersegment revenues | 0 | 0 | 0 | 0 | |
Less: cost of operations | (398) | (395) | (842) | (825) | |
Other non-interest income | 0 | 2,216 | |||
EBITDA | (398) | (395) | (842) | 1,391 | |
Capital expenditures | 0 | 0 | 0 | 0 | |
Identifiable assets | 964 | 1,048 | 964 | 1,048 | |
Total | |||||
Revenue from operations | 89,115 | 57,337 | 161,361 | 109,942 | |
Intersegment revenues | 875 | 0 | 1,546 | 0 | |
Less: cost of operations | (86,941) | (81,450) | (159,028) | (137,075) | |
Other non-interest income | 0 | 2,216 | |||
Depletion, depreciation and amortization | (463) | (449) | (918) | (900) | |
Interest expense, net | (750) | (831) | (1,493) | (1,426) | |
Income (loss) before income taxes | 1,836 | (25,393) | 1,468 | (27,243) | |
Income tax benefit | 0 | 0 | 217 | 0 | |
Net income (loss) | 1,836 | (25,393) | 1,685 | (27,243) | |
Capital expenditures | 827 | 858 | 1,449 | 2,889 | |
Identifiable assets | $ 75,247 | $ 72,484 | $ 75,247 | $ 72,484 |
6. Prepaid Expenses and Other40
6. Prepaid Expenses and Other Current Assets (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Prepaid crude oil and condensate | $ 1,839 | $ 913 |
Prepaid insurance | 478 | 294 |
Prepaid expenses, net | $ 2,317 | $ 1,207 |
7. Inventory (Details)
7. Inventory (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Inventory Disclosure [Abstract] | ||
AGO | $ 1,945 | $ 213 |
Crude oil and condensate | 1,573 | 961 |
Naphtha | 417 | 170 |
Chemicals | 224 | 162 |
Propane | 16 | 17 |
LPG mix | 5 | 8 |
HOBM | 0 | 1,558 |
Inventories, net | $ 4,180 | $ 3,089 |
8. Property, Plant and Equipm42
8. Property, Plant and Equipment, Net (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Property, Plant and Equipment [Abstract] | ||
Refinery and facilities | $ 54,114 | $ 51,432 |
Land | 566 | 566 |
Other property and equipment | 747 | 653 |
Property, Plant and Equipment, Gross | 55,427 | 52,651 |
Less: Accumulated depletion, depreciation and amortization | (9,414) | (8,495) |
Property, plant and equipment, gross | 46,013 | 44,156 |
Construction in progress | 18,979 | 20,441 |
Property, plant and equipment, net | $ 64,992 | $ 64,597 |
8. Property, Plant and Equipm43
8. Property, Plant and Equipment, Net (Details Narrative) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | ||
Interest cost capitalized | $ 3,700 | $ 3,900 |
9. Related Party Transactions44
9. Related Party Transactions (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Prepaid operating expenses, related party | $ 6,060 | $ 5,608 |
Less: Long-term debt - current portion, related party | (6,060) | (4,000) |
Long-term debt - net of current portion, related party | 0 | 1,608 |
LEH [Member] | ||
Prepaid operating expenses, related party | 4,036 | 4,000 |
Ingleside [Member] | ||
Prepaid operating expenses, related party | 1,238 | 1,169 |
Jonathan Carroll [Member] | ||
Prepaid operating expenses, related party | $ 786 | $ 439 |
9. Related Party Transactions45
9. Related Party Transactions (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Total | $ 89,115 | $ 57,337 | $ 161,361 | $ 109,942 |
Total, percentage | 100.00% | 100.00% | 100.00% | 100.00% |
LEH [Member] | ||||
Jet fuel product sales | $ 25,549 | $ 20,158 | $ 46,116 | $ 35,558 |
HOBM sales | 0 | 0 | 0 | 3,657 |
Jet fuel storage fees | $ 0 | $ 375 | $ 0 | $ 750 |
Jet fuel product sales, percentage | 28.70% | 35.20% | 28.60% | 32.30% |
HOBM sales, percentage | 0.00% | 0.00% | 0.00% | 3.30% |
Jet fuel storage fees, percentage | 0.00% | 0.60% | 0.00% | 0.70% |
Other Customers [Member] | ||||
Product sales | $ 62,716 | $ 36,475 | $ 113,661 | $ 69,320 |
Tolling and terminaling | $ 850 | $ 329 | $ 1,584 | $ 657 |
Product sales, percentage | 70.40% | 63.60% | 70.40% | 63.10% |
Tolling and terminaling, percentage | 0.90% | 0.60% | 1.00% | 0.60% |
9. Related Party Transactions46
9. Related Party Transactions (Details 2) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018USD ($)$ / bbl | Jun. 30, 2017USD ($)$ / bbl | Jun. 30, 2018USD ($)$ / bbl | Jun. 30, 2017USD ($)$ / bbl | |
Refinery operating expenses, Amount | $ | $ 1,377 | $ 1,652 | $ 3,299 | $ 4,465 |
Refinery operating expenses, Per bbl | $ / bbl | 1.16 | 1.53 | 1.51 | 2.14 |
LEH [Member] | ||||
Refinery operating expenses, Amount | $ | $ 1,377 | $ 1,652 | $ 3,299 | $ 4,465 |
Refinery operating expenses, Per bbl | $ / bbl | 1.16 | 1.53 | 1.51 | 2.14 |
9. Related Party Transactions47
9. Related Party Transactions (Details 3) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Interest expenses under loan and guarantee, related party | $ 364 | $ 400 | $ 734 | $ 776 |
Jonathan Carroll [Member] | ||||
Interest expenses under loan and guarantee, related party | 177 | 166 | 340 | 334 |
LEH [Member] | ||||
Interest expenses under loan and guarantee, related party | 163 | 211 | 323 | 396 |
Ingleside [Member] | ||||
Interest expenses under loan and guarantee, related party | $ 24 | $ 23 | $ 71 | $ 46 |
9. Related Party Transactions48
9. Related Party Transactions (Details Narrative) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Prepaid related party operating expenses | $ 6,060 | $ 5,608 |
Accounts payable, related party | 1,226 | 974 |
Jonathan Carroll [Member] | ||
Prepaid related party operating expenses | 786 | 439 |
Ingleside [Member] | ||
Prepaid related party operating expenses | 1,238 | 1,169 |
LEH [Member] | ||
Prepaid related party operating expenses | $ 4,036 | $ 4,000 |
10. Accrued Expenses and Othe49
10. Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Disclosure Text Block Supplement [Abstract] | ||
Unearned revenue | $ 2,721 | $ 450 |
Board of director fees payable | 241 | 207 |
Other payable | 213 | 116 |
Customer deposits | 109 | 109 |
Property taxes | 81 | 131 |
Excise and income taxes payable | 78 | 79 |
Insurance | 44 | 68 |
Accrued Expenses and Other Current Liabilities, Net | $ 3,487 | $ 1,160 |
11. Long-Term Debt, Net (Detail
11. Long-Term Debt, Net (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Principal balance outstanding | $ 37,285 | $ 37,679 |
Less: Current portion of long-term debt, net | (35,194) | (35,544) |
Less: Unamortized debt issue costs | (2,070) | (2,135) |
Long term debt | 21 | 0 |
First Term Loan Due 2034 [Member] | ||
Principal balance outstanding | 22,841 | 23,199 |
Second Term Loan Due 2034 [Member] | ||
Principal balance outstanding | 9,404 | 9,502 |
Notre Dame Debt [Member] | ||
Principal balance outstanding | 4,978 | 4,978 |
Capital Leases [Member] | ||
Principal balance outstanding | $ 62 | $ 0 |
11. Long-Term Debt, Net (Deta51
11. Long-Term Debt, Net (Details 1) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Debt Disclosure [Abstract] | ||
First Term Loan Due 2034 | $ 1,674 | $ 1,674 |
Second Term Loan Due 2034 | 768 | 768 |
Less: Accumulated amortization | (372) | (307) |
Long term debt | $ 2,070 | $ 2,135 |
11. Long-Term Debt, Net (Deta52
11. Long-Term Debt, Net (Details 2) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Long-term Debt Net Details 2 | ||
Notre Dame Debt | $ 2,444 | $ 2,046 |
LEH Loan Agreement (related party) | 1,214 | 892 |
Second Term Loan Due 2034 | 49 | 49 |
First Term Loan Due 2034 | 36 | 40 |
Total | 3,743 | 3,027 |
Less: Interest payable, current portion | (3,743) | (3,027) |
Long term debt | $ 0 | $ 0 |
11. Long-Term Debt, Net (Deta53
11. Long-Term Debt, Net (Details 3) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Debt Disclosure [Abstract] | ||
Crane | $ 94 | $ 0 |
Less: accumulated depreciation | (7) | 0 |
Capital lease obligation | $ 87 | $ 0 |
11. Long-Term Debt, Net (Deta54
11. Long-Term Debt, Net (Details Narrative) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Amortization expense | $ 30 | $ 30 | $ 60 | $ 60 |
Second Term Loan Due 2034 | ||||
Guaranty fees | $ 100 | $ 100 | $ 200 | $ 200 |
12. Asset Retirement Obligati55
12. Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |||||
Asset retirement obligations, at the beginning of the period | $ 2,315 | $ 2,028 | $ 2,028 | ||
Accretion expense | $ 78 | $ 72 | 143 | $ 144 | 287 |
Asset retirement obligations | 2,458 | 2,458 | 2,315 | ||
Less: asset retirement obligations, current portion | (2,458) | (2,458) | (2,315) | ||
Long-term asset retirement obligations, at the end of the period | $ 0 | $ 0 | $ 0 |
13. Treasury Stock (Details Nar
13. Treasury Stock (Details Narrative) - shares | Jun. 30, 2018 | Dec. 31, 2017 |
Equity [Abstract] | ||
Treasury stock | 0 | 0 |
14. Concentration of Risk (Deta
14. Concentration of Risk (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Total refined petroleum product sales | $ 88,265 | $ 56,633 | $ 159,777 | $ 108,535 |
Concentration Risk | 100.00% | 100.00% | 100.00% | 100.00% |
LPG mix | ||||
Total refined petroleum product sales | $ 0 | $ 0 | $ 3 | $ 121 |
Concentration Risk | 0.00% | 0.00% | 0.00% | 0.10% |
Naphtha | ||||
Total refined petroleum product sales | $ 23,648 | $ 13,254 | $ 39,966 | $ 27,017 |
Concentration Risk | 26.80% | 23.40% | 25.00% | 24.90% |
Jet Fuel | ||||
Total refined petroleum product sales | $ 25,549 | $ 20,158 | $ 46,116 | $ 35,558 |
Concentration Risk | 28.90% | 35.60% | 28.90% | 32.80% |
HOBM | ||||
Total refined petroleum product sales | $ 22,430 | $ 10,883 | $ 38,859 | $ 21,569 |
Concentration Risk | 25.40% | 19.20% | 24.30% | 19.90% |
AGO | ||||
Total refined petroleum product sales | $ 16,638 | $ 12,338 | $ 34,833 | $ 24,270 |
Concentration Risk | 18.90% | 21.80% | 21.80% | 22.30% |
14. Concentration of Risk (De58
14. Concentration of Risk (Details Narrative) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Concentration Risk | 100.00% | 100.00% | 100.00% | 100.00% | |
FDIC insurance limit | $ 1,400 | $ 1,400 | $ 1,600 |
15. Leases (Details Narrative)
15. Leases (Details Narrative) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Leases, Operating [Abstract] | ||||
Rent expense | $ 60 | $ 50 | $ 110 | $ 130 |
16. Income Taxes (Details)
16. Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Income Taxes Details Abstract | |||||
Current | $ 108 | $ 0 | |||
Impact of change in enacted tax rates | 0 | (6,654) | |||
Change in valuation allowance | 109 | 6,654 | |||
Total provision for income taxes | $ 0 | $ 0 | $ (217) | $ 0 | $ 0 |
16. Income Taxes (Details 1)
16. Income Taxes (Details 1) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Deferred tax assets: | ||
Net operating loss and capital loss carryforwards | $ 10,641 | $ 9,767 |
Accrued arbitration award payable | 3,180 | 4,122 |
Start-up costs (crude oil and condensate processing facility) | 721 | 763 |
Asset retirement obligations liability/deferred revenue | 520 | 495 |
AMT credit and other | 100 | 217 |
Total deferred tax assets | 15,162 | 15,365 |
Deferred tax liabilities: | ||
Basis differences in property and equipment | (4,764) | (4,415) |
Total deferred tax liabilities | (4,764) | (4,415) |
Deferred tax assets, net | 10,398 | 10,950 |
Valuation allowance | (10,290) | (10,950) |
Deferred tax assets, net | $ 108 | $ 0 |
16. Income Taxes (Details 2)
16. Income Taxes (Details 2) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Beginning balance | $ 39,832 | $ 33,176 |
Net operating losses | 4,160 | 6,656 |
Ending balance | 43,992 | 39,832 |
Pre-Ownership Change [Member] | ||
Beginning balance | 9,614 | 9,614 |
Net operating losses | 0 | 0 |
Ending balance | 9,614 | 9,614 |
Post-Ownership Change [Member] | ||
Beginning balance | 30,218 | 23,562 |
Net operating losses | 4,160 | 6,656 |
Ending balance | $ 34,378 | $ 30,218 |
16. Income Taxes (Details Narra
16. Income Taxes (Details Narrative) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||||
Income Tax Benefit | $ 0 | $ 0 | $ (217) | $ 0 | $ 0 |
17. Earnings per share (Details
17. Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Earnings Per Share [Abstract] | ||||
Net income (loss) | $ 1,836 | $ (25,393) | $ 1,685 | $ (27,243) |
Basic and diluted income per share | $ 0.17 | $ (0.0239) | $ 0.15 | $ (2.58) |
Basic and diluted | ||||
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock | 10,925,513 | 10,637,101 | 10,925,513 | 10,556,356 |