BLUE DOLPHIN ENERGY CO - Quarter Report: 2016 September (Form 10-Q)

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

☑ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the quarterly period ended:  September 30, 2016

 

☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from _____________ to_____________

 

Commission File Number: 0-15905

 

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

 

Delaware		73-1268729
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

 

801 Travis Street, Suite 2100, Houston, Texas 77002

(Address of principal executive offices)

 

(713) 568-4725

(Registrant’s telephone number, including area code)

 

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

 

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

 

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

 

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒
(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

 

Number of shares of common stock, par value $0.01 per share outstanding as of November 14, 2016:  10,474,714

 

 

 

TABLE OF CONTENTS

 

GLOSSARY OF SELECTED OIL AND GAS TERMS		3
PART I.	FINANCIAL INFORMATION	5
ITEM 1.	FINANCIAL STATEMENTS	5
	Consolidated Balance Sheets (Unaudited)	5
	Consolidated Statements of Operations (Unaudited)	6
	Consolidated Statements of Cash Flows (Unaudited)	7
	Notes to Consolidated Financial Statements	8
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 4.	CONTROLS AND PROCEDURES	59
PART II	OTHER INFORMATION	60
ITEM 1.	LEGAL PROCEEDINGS	60
ITEM 1A.	RISK FACTORS	60
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	61
ITEM 4.	MINE SAFETY DISCLOSURES	61
ITEM 5.	OTHER INFORMATION	61
ITEM 6.	EXHIBITS	61
SIGNATURES		63

 

 

GLOSSARY OF SELECTED OIL AND GAS TERMS

 

The following are abbreviations and definitions of certain commonly used oil and gas industry terms that are used in this Form 10-Q for the quarterly period ended September 30, 2016 (this “Quarterly Report”):

 

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Consolidated Balance Sheets (Unaudited)

 

	September 30,	December 31,
	2016	2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$1,677,485	$1,853,875
Restricted cash	4,160,999	3,175,299
Accounts receivable, net	7,412,697	5,457,245
Prepaid expenses and other current assets	196,101	939,690
Deposits	136,970	395,414
Inventory	8,819,980	7,808,318
Total current assets	22,404,232	19,629,841
Total property and equipment, net	61,283,727	48,841,812
Restricted cash, noncurrent	4,358,581	15,616,478
Surety bonds	710,000	1,022,000
Trade name	303,346	303,346
Deferred tax assets, net	7,342,277	3,607,237
Total long-term assets	73,997,931	69,390,873
TOTAL ASSETS	$96,402,163	$89,020,714
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$23,886,185	$14,882,714
Accounts payable, related party	-	300,000
Asset retirement obligations, current portion	25,972	38,644
Accrued expenses and other current liabilities	3,063,080	2,990,891
Interest payable, current portion	158,706	81,467
Long-term debt less unamortized debt issue costs, current portion	32,120,782	1,934,932
Long-term debt, related party, current portion	500,000	-
Total current liabilities	59,754,725	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,983,042	1,947,220
Deferred revenues and expenses	93,814	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,342,363	32,846,254
Long-term debt, related party, net of current portion	6,398,931	-
Long-term interest payable, net of current portion	1,638,952	1,482,801
Total long-term liabilities	11,457,102	36,401,360
TOTAL LIABILITIES	71,211,827	56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,614,715 and
10,603,802 shares issued at September 30, 2016 and December 31, 2015, respectively)	106,148	106,038
Additional paid-in capital	36,788,628	36,738,737
Accumulated deficit	(10,904,440)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	25,190,336	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$96,402,163	$89,020,714

 

See accompanying notes to consolidated financial statements. 

 

Consolidated Statements of Operations (Unaudited)

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
REVENUE FROM OPERATIONS
Refined petroleum product sales	$53,951,293	$54,924,070	$126,546,716	$174,830,292
Tank rental revenue	717,487	286,892	1,624,461	860,676
Pipeline operations	19,526	45,925	71,865	119,882
Total revenue from operations	54,688,306	55,256,887	128,243,042	175,810,850
COST OF OPERATIONS
Cost of refined products sold	51,689,474	48,415,627	125,316,249	151,604,774
Refinery operating expenses	3,153,646	2,953,528	9,468,409	8,420,650
Joint Marketing Agreement profit share	965,627	1,435,376	392,062	4,812,674
Pipeline operating expenses	91,969	63,099	266,454	170,582
Lease operating expenses	9,005	(1,143)	32,112	20,271
General and administrative expenses	891,210	312,365	1,503,533	1,058,267
Depletion, depreciation and amortization	504,719	414,837	1,415,519	1,217,005
Recovery of bad debt	-	-	(139,868)	-
Accretion expense	28,186	52,720	84,558	158,655
Total cost of operations	57,333,836	53,646,409	138,339,028	167,462,878
Income (loss) from operations	(2,645,530)	1,610,478	(10,095,986)	8,347,972
OTHER INCOME (EXPENSE)
Easement, interest and other income	157,840	724,349	415,700	856,816
Interest and other expense	(485,659)	(382,191)	(1,305,125)	(1,322,562)
Total other income (expense)	(327,819)	342,158	(889,425)	(465,746)
Income (loss) before income taxes	(2,973,349)	1,952,636	(10,985,411)	7,882,226
Income tax benefit (expense)	1,034,798	(688,403)	3,735,040	(2,778,750)
Net income (loss)	$(1,938,551)	$1,264,233	$(7,250,371)	$5,103,476
Income (loss) per common share:
Basic	$(0.19)	$0.12	$(0.69)	$0.49
Diluted	$(0.19)	$0.12	$(0.69)	$0.49
Weighted average number of common shares outstanding:
Basic	10,464,715	10,453,802	10,460,849	10,451,168
Diluted	10,464,715	10,453,802	10,460,849	10,451,168

 

See accompanying notes to consolidated financial statements.

 

Consolidated Statements of Cash Flows (Unaudited)

 

	Nine Months Ended September 30,
	2016	2015
OPERATING ACTIVITIES
Net income (loss)	$(7,250,371)	$5,103,476
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization	1,415,519	1,217,005
Unrealized loss (gain) on derivatives	1,143,490	362,750
Deferred tax expense (benefit)	(3,735,040)	2,479,823
Amortization of debt issue costs	96,364	517,652
Accretion expense	84,558	158,655
Common stock issued for services	50,000	19,999
Recovery of bad debt	(139,868)	-
Changes in operating assets and liabilities
Accounts receivable	(1,815,584)	506,784
Prepaid expenses and other current assets	945,539	(274,435)
Deposits and other assets	570,444	(1,711,073)
Inventory	(1,011,662)	(2,420,176)
Accounts payable, accrued expenses and other liabilities	5,269,224	1,172,976
Accounts payable, related party	(300,000)	(1,174,168)
Net cash provided by (used in) operating activities	(4,677,387)	5,959,268
INVESTING ACTIVITIES
Capital expenditures	(11,255,725)	(8,156,298)
Change in restricted cash for investing activities	11,257,897	(13,021,438)
Net cash provided by (used in) investing activities	2,172	(21,177,736)
FINANCING ACTIVITIES
Proceeds from issuance of debt	6,898,931	28,000,000
Payments on long-term debt	(1,414,406)	(9,474,720)
Change in restricted cash for financing activities	(985,700)	(3,081,686)
Net cash provided by financing activities	4,498,825	15,443,594
Net increase (decrease) in cash and cash equivalents	(176,390)	225,126
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,853,875	1,293,233
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$1,677,485	$1,518,359
Supplemental Information:
Non-cash investing and financing activities:
Financing of capital expenditures via accounts payable	$2,601,709	$1,743,997
Interest paid	$1,827,794	$959,665
Income taxes paid	$-	$139,500

 

 

See accompanying notes to consolidated financial statements.

Notes to Consolidated Financial Statements
(1)	Organization

 

Nature of Operations. Blue Dolphin Energy Company (“Blue Dolphin,”) is primarily an independent refiner and marketer of petroleum products. Our primary asset is a 15,000 bpd crude oil and condensate processing facility that is located in Nixon, Texas (the “Nixon Facility”). As part of our refinery business segment, we conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. We also own and operate pipeline assets and have leasehold interests in oil and gas properties. (See “Note (4) Business Segment Information” for further discussion of our business segments.)

 

Structure and Management. Blue Dolphin was formed as a Delaware corporation in 1986. We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the “Operating Agreement”). Jonathan Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer, and President of Blue Dolphin, as well as a majority owner of LEH. (See “Note (8) Related Party Transactions,” “Note (9) Long-Term Debt, Net,” and “Note (19) Commitments and Contingencies – Financing Agreements” for additional disclosures related to LEH, the Operating Agreement, and Jonathan Carroll.)

 

Our operations are conducted through the following active subsidiaries:

 

 

 

 

 

 

See "Part I, Item 1. Business and Item 2. Properties” in our Form 10-K for the fiscal year ended December 31, 2015 (the “Annual Report”) as filed with the Securities and Exchange Commission (the “SEC”) 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.

 

Operating Risks. Execution of our business strategy depends on several factors, including adequate crude oil and condensate sourcing, levels of accounts receivable, refined petroleum product inventories, accounts payable, capital expenditures, and adequate access to credit on satisfactory terms. These factors may be impacted by general economic, political, financial, competitive, and other factors that are beyond our control.  There can be no assurance that our business and operational strategy will achieve anticipated outcomes.  Our operations, liquidity, and financial condition may be materially adversely affected if: (i) our strategy is not successful, (ii) our working capital requirements are not funded through Operations Payments by GEL TEX Marketing, LLC (“GEL”) under a Joint Marketing Agreement (the “Joint Marketing Agreement”), our profit share under the Joint Marketing Agreement, or certain advances from LEH, or (iii) we have future covenant violations under our loan agreements that are not waived.

 

For the three months ended September 30, 2016, we had a net loss of $1,938,551 compared to net income of $1,264,233 for the three months ended September 30, 2015. For the nine months ended September 30, 2016, we had a net loss of $7,250,371 compared to net income of $5,103,476 for the nine months ended September 30, 2015.

 

 

As of September 30, 2016, we had cash and cash equivalents and restricted cash (current portion) of $1,677,485 and $4,160,999, respectively. As of September 30, 2016, we had current assets of $22,404,232 and current liabilities (including the current portion of long-term debt) of $59,754,725, reflecting a working capital deficit of $37,350,493. Excluding the current portion of long-term debt, we had a working capital deficit of $5,229,711 as of September 30, 2016. Non-payment of Operations Payments to us by GEL under the Joint Marketing Agreement resulting from a contract-related dispute between the parties contributed to the working capital deficit as of September 30, 2016. (See “Note (19) Commitments and Contingencies – Genesis Agreements and Legal Matters” for a discussion related to Operations Payments and the Joint Marketing Agreement.)

 

As of December 31, 2015, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively. As of December 31, 2015, we had current assets of $19,629,841 and current liabilities (including the current portion of long-term debt) of $20,228,648, reflecting a working capital deficit of $598,807.

 

In addition to the Joint Marketing Agreement, we are party to a variety of contracts and agreements with Genesis and its affiliates that enable the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and its affiliates have successive one-year renewals until August 2019 unless sooner terminated by Genesis or its affiliates with 180 days’ prior written notice.   An adverse change in our relationship with Genesis could have a material adverse effect on our operations, liquidity, and financial condition. We are currently involved in a dispute with Genesis over certain contractual matters. (See “Note (19) Commitments and Contingencies – Genesis Agreements” and “Legal Matters,” as well as “Part II. Other Information, Item 1A. Risk Factors” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and information regarding the current contract-related dispute with Genesis.)

 

As of September 30, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign Bank (“Sovereign”). As a result of these covenant defaults, Sovereign could declare the amounts owed under these loan agreements immediately due and payable, exercise its rights with respect to collateral securing our obligations under these loan agreements, and/or exercise any other rights and remedies available.  Sovereign waived the financial covenant defaults as of the quarter ended September 30, 2016. However, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheets due to the uncertainty of our ability to meet the financial covenants in the future. There can be no assurance that Sovereign will provide future waivers, which may have an adverse impact on our financial position and results of operations. (See “Note (9) Long-Term Debt, Net” and “Note (20) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

 

(2)	Basis of Presentation

 

The accompanying unaudited consolidated financial statements, which include Blue Dolphin and subsidiaries, have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim consolidated financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. 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, 2015 has been 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 nine months ended September 30, 2016 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2016, or for any other period.

 

(3)	Significant Accounting Policies

 

The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and 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. We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated.

 

Cash and Cash Equivalents. Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents totaled $1,677,485 and $1,853,875 as of September 30, 2016 and December 31, 2015, respectively.

 

Restricted Cash. As of September 30, 2016, total restricted cash was $8,519,580, comprised of restricted cash (current portion) totaling $4,160,999 and restricted cash, noncurrent totaling $4,358,581. As of December 31, 2015, total restricted cash was $18,791,777, comprised of restricted cash (current portion) totaling $3,175,299 and restricted cash, noncurrent totaling $15,616,478. Restricted cash (current portion) primarily represents: (i) amounts held in our disbursement account with Sovereign attributable to construction invoices awaiting payment from that account, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a construction contingency account under which Sovereign will fund contingencies. Restricted cash, noncurrent represents funds held in the Sovereign disbursement account for payment of future construction related expenses to build new petroleum storage tanks. (See “Note (9) Long-Term Debt, Net” for additional disclosures related to our loan agreements with Sovereign.)

 

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. Allowance for doubtful accounts totaled $0 and $139,868 as of September 30, 2016 and December 31, 2015, respectively.

 

Inventory. The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. (See “Note (6) Inventory” for additional disclosures related to our inventory.)

 

Derivatives. We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, commodity futures contracts may be used to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash.

 

Although these commodity futures contracts are not subject to hedge accounting treatment under Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) guidance, we record the fair value of these hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets, and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of operations. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of operations using mark-to-market accounting.

 

(See “Note (17) Fair Value Measurement” and “Note (18) Inventory Risk Management” for additional disclosures related to derivatives.)

 

 

Property and Equipment.

 

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances.

 

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. We did not record any impairment of our refinery and facilities assets for any period presented.

 

Pipelines and Facilities. We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, 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.

 

Oil and Gas Properties. We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis.  Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three and nine months ended September 30, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired as of December 31, 2012.

 

Construction in Progress. Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service.

 

(See “Note (7) 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. We have an intangible asset consisting of the Blue Dolphin Energy Company trade name in the amount of $303,346 on our consolidated balance sheets as of September 30, 2016 and December 31, 2015. We have determined the trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill, and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2015. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2015.

 

Revenue Recognition.

 

Refined Petroleum Products Revenue. Jet fuel, our only finished product, is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold in nearby markets to wholesalers and refiners for further blending and processing. Revenue from refined petroleum products sales is recognized when sales prices are fixed or determinable, collectability is reasonably assured, and title passes. Title passage occurs when refined petroleum products are delivered in accordance with the terms of the respective sales agreements, and customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue.

 

Tank Rental Revenue. Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned.

 

Easement Revenue. Land easement revenue is recognized monthly as earned and is included in other income.

 

Pipeline Transportation Revenue. Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline.

 

Deferred Revenue. In 2014, we increased the ownership interest in our pipeline assets from approximately 83% to 100% pursuant to an Asset Sale Agreement (the “Purchase Agreement”) with a former partner. Pursuant to the Purchase Agreement, the former partner paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the pipeline assets. We recorded the amount received for our benefit related to the supplemental pipeline bonds as deferred revenue. We recognized the deferred revenue on a straight-line basis through December 31, 2018, the expected retirement date of the associated assets. In 2015, a significant portion of the remaining deferred revenue was recognized as a result of abandoning a segment of the pipeline assets. (See “Part I, Business – Governmental Regulation – Offshore Safety and Environmental Oversight – Decommissioning Requirements” in our Annual Report for a discussion related to supplemental pipeline bonds.)

 

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 three and nine month periods 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.

 

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

 

(See “Note (15) 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.

 

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

 

Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities 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 (11) 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 numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity.

 

The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services 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 (16) Earnings Per Share” for additional information related to EPS.)

 

Stock-Based Compensation. In accordance with FASB ASC guidance for stock-based compensation, share-based payments to directors, including the issuance of restricted common stock, are measured at fair value as of the date of grant and are expensed in our consolidated statements of operations over the service period (generally the vesting period).

 

Treasury Stock. We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. (See “Note (12) 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. For the three and nine months ended September 30, 2016, we adopted the following recently issued ASU’s:

 

ASU 2015-17, Income Taxes (Topic 740). In November 2015, FASB issued ASU 2015-17. This guidance simplifies the presentation of deferred income taxes by requiring that deferred tax liabilities and assets be classified as noncurrent instead of separated into current and noncurrent. We adopted this accounting pronouncement effective April 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net. The adoption of ASU 2015-17 had no impact on our results of operations or cash flows.

 

ASU 2015-03, Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. In April 2015, FASB issued ASU 2015-03. This guidance requires debt issue costs to be presented as an offset to their related debt. We adopted this accounting pronouncement effective January 1, 2016. Accordingly, our consolidated balance sheet as of December 31, 2015 has been changed to reclassify approximately $2.4 million previously reported as debt issue costs as a direct deduction of long-term debt. The adoption of ASU 2015-03 had no impact on our results of operations or cash flows.

 

New Pronouncements Issued But Not Yet Effective. The following are recently issued, but not yet effective, ASU’s that may have an effect on our consolidated financial position, results of operations, or cash flows:

 

ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. In August 2016, FASB issued ASU 2016-15. This guidance addresses eight specific cash flow issues in order to reduce future diversity of practice. For public business entities, the amendments in ASU 2016-15 are effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated statements of cash flows.

 

ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments). In June 2016, FASB issued ASU 2016-13. This guidance updates the current impairment model to incorporate both expected and incurred credit losses, eliminating potential overstatements of assets and resulting in more timely recognition of losses. For a public business entity, the amendments in ASU 2016-13 are effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early application as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated financial statements.

 

ASU 2016-02, Leases (Topic 842). In February 2016, FASB issued ASU 2016-02. This guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. For a public business entity, the amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. We are evaluating the impact that adoption of this guidance will have on our consolidated balance sheets.

 

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory. In July 2015, FASB issued ASU 2015-11. Current guidance requires an entity to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Under ASU 2015-11, an entity should measure inventory at the lower of cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Amendments under ASU 2015-11 more closely align the measurement of inventory in GAAP with the measurement of inventory in International Financial Reporting Standards. For public business entities, ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. ASU 2015-11 should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

 

ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40). In August 2014, FASB issued ASU 2014-15, which requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern for a one-year period subsequent to the date of the financial statements. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for all entities for the first annual period ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We do not anticipate adoption of this guidance to have a material effect on our consolidated financial statements.

 

ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In May 2014, FASB and the International Accounting Standards Board (the “IASB”) issued ASU 2014-09, a converged standard on recognition of revenue from contracts with customers. In June 2014, the FASB and the IASB (collectively, the “Accounting Boards”) formed the FASB-IASB Joint Transition Resource Group for Revenue Recognition (the “TRG”). The primary objective of the TRG is to inform the Accounting Boards about potential implementation issues that could arise when organizations implement the new revenue guidance. Resultant ASU’s as part of the TRG process include:

 

 

 

 

 

 

 

We are evaluating the impact that adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, and ASU 2016-12, all of which relate to Revenue from Contracts with Customers (Topic 606), will have on our consolidated financial statements.

 

Other new pronouncements issued but not effective until after September 30, 2016 are not expected to have a material impact on our financial position, results of operations, or liquidity.

 

Reclassification. We have reclassified certain prior year amounts to conform to our 2016 presentation.

 

 

Remainder of Page Intentionally Left Blank

 

 

 

 

 

(4)	Business Segment Information

 

We have two reportable business segments: (i) Refinery Operations and (ii) Pipeline Transportation. Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility. Business activities related to our Pipeline Transportation business segment are primarily conducted in the Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties.

 

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

 

	Three Months Ended September 30, 2016				Three Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$54,668,780	$19,526	$-	$54,688,306	$55,210,962	$45,925	$-	$55,256,887
Less: cost of operations(1)	(55,495,575)	(129,160)	(238,755)	(55,863,490)	(51,444,705)	(114,675)	(236,816)	(51,796,196)
Other non-interest income(2)	-	156,396	-	156,396	-	62,500	660,000	722,500
Adjusted EBITDA(3)	(826,795)	46,762	(238,755)	(1,018,788)	3,766,257	(6,250)	423,184	4,183,191
Less: JMA Profit Share(4)	(965,627)	-	-	(965,627)	(1,435,376)	-	-	(1,435,376)
EBITDA(3)	$(1,792,422)	$46,762	$(238,755)		$2,330,881	$(6,250)	$423,184
Depletion, depreciation and amortization				(504,719)				(414,837)
Interest expense, net				(484,215)				(380,342)
Income (loss) before income taxes				(2,973,349)				1,952,636
Income tax benefit (expense)				1,034,798				(688,403)
Net income (loss)				$(1,938,551)				$1,264,233
Capital expenditures(5)	$4,182,747	$-	$-	$4,182,747	$2,355,811	$-	$-	$2,355,811
Identifiable assets(6)	$85,585,499	$3,106,327	$7,710,337	$96,402,163	$78,145,626	$3,303,803	$3,405,977	$84,855,406

 

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “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 adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.

 

 

Business segment information for the periods indicated (and as of the dates indicated), was as follows:

 

	Nine Months Ended September 30, 2016				Nine Months Ended September 30, 2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$128,171,177	$71,865	$-	$128,243,042	$175,690,968	$119,882	$-	$175,810,850
Less: cost of operations(1)	(135,452,537)	(383,124)	(695,786)	(136,531,447)	(160,208,576)	(296,291)	(928,331)	(161,433,198)
Other non-interest income(2)	-	412,061	-	412,061	-	187,500	660,000	847,500
Adjusted EBITDA(3)	(7,281,360)	100,802	(695,786)	(7,876,344)	15,482,392	11,091	(268,331)	15,225,152
Less: JMA Profit Share(4)	(392,062)	-	-	(392,062)	(4,812,674)	-	-	(4,812,674)
EBITDA(3)	$(7,673,422)	$100,802	$(695,786)		$10,669,718	$11,091	$(268,331)
Depletion, depreciation and
amortization				(1,415,519)				(1,217,005)
Interest expense, net				(1,301,486)				(1,313,247)
Income (loss) before income taxes				(10,985,411)				7,882,226
Income tax benefit (expense)				3,735,040				(2,778,750)
Net income (loss)				$(7,250,371)				$5,103,476
Capital expenditures(5)	$11,255,725	$-	$-	$11,255,725	$8,156,298	$-	$-	$8,156,298
Identifiable assets(6)	$85,585,499	$3,106,327	$7,710,337	$96,402,163	$78,145,626	$3,303,803	$3,405,977	$84,855,406

 

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
(2)	Other non-interest income reflects FLNG easement revenue. (See “Note (19) Commitments and Contingencies – FLNG Master Easement Agreement” for further discussion related to FLNG.)
(3)	Adjusted EBITDA and EBITDA are non-GAAP financial measures. See “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 adjusted EBITDA and EBITDA.
(4)	The JMA Profit Share represents the GEL TEX Marketing, LLC Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Note (19) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement.)
(5)	Capital expenditures for the prior year period reflect reclassification of capital expenditures funded by credit facilities to conform to the 2016 presentation.
(6)	Identifiable assets for the prior year period reflect reclassification of debt issue costs as a reduction in long-term debt to conform to the 2016 presentation.
(5)	Prepaid Expenses and Other Current Assets

 

Prepaid expenses and other current assets as of the dates indicated consisted of the following:

 

	September 30,	December 31,
	2016	2015
Prepaid insurance	$192,351	$315,120
Prepaid listing fees	3,750	-
Prepaid related party operating expenses	-	624,570
	$196,101	$939,690

 

 

(6)

Inventory

 

Inventory as of the dates indicated consisted of the following:

 

	September 30,	December 31,
	2016	2015
HOBM	$4,069,203	$5,007,576
Jet fuel	3,744,702	2,045,784
Naphtha	417,223	309,850
AGO	280,277	278,278
Chemicals	261,518	122,777
Propane	24,860	17,860
Crude oil and condensate	19,041	19,041
LPM mix	3,156	7,152
	$8,819,980	$7,808,318

 

(7)	Property, Plant and Equipment, Net

 

Property, plant and equipment, net, as of the dates indicated consisted of the following:

 

	September 30,	December 31,
	2016	2015
Refinery and facilities	$50,516,486	$40,195,928
Pipelines and facilities	2,127,207	2,127,207
Onshore separation and handling facilities	325,435	325,435
Land	602,938	602,938
Other property and equipment	652,795	644,795
	54,224,861	43,896,303
Less: Accumulated depletion, depreciation, and amortization	(7,649,077)	(6,234,161)
	46,575,784	37,662,142
Construction in progress	14,707,943	11,179,670
	$61,283,727	$48,841,812

 

We capitalize interest cost incurred on funds used to construct property, plant, and equipment. The capitalized interest is recorded as part of the asset to which it relates and is depreciated over the asset’s useful life. Interest cost capitalized was $1,776,863 and $556,032 as of September 30, 2016 and December 31, 2015, respectively.

 

 

(8)	Related Party Transactions

 

We are party to several agreements with related parties. We believe these related party transactions were consummated on terms equivalent to those that prevail in arm's-length transactions. A summary of these agreements follows:

 

LEH. We are party to an Operating Agreement, a Product Sales Agreement, a Terminal Services Agreement, a Loan and Security Agreement, and a Promissory Note with LEH. LEH, our controlling shareholder, owns approximately 81% of our Common Stock. Jonathan Carroll, Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin, is the majority owner of LEH.

 

Operating Agreement. LEH manages and operates all of our properties pursuant to the Operating Agreement. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party. For services rendered under the Operating Agreement, LEH receives reimbursements and fees as follows:

 

 

 

Product Sales Agreement. Under a Product Sales Agreement, LEH purchases jet fuel from the Nixon Facility for resale to third parties. Sales to LEH under the Product Sales Agreement are reflected within refined petroleum product sales in our consolidated statements of operations.

 

Terminal Services Agreement. Pursuant to a Terminal Services Agreement, LEH leases a petroleum storage tank at the Nixon Facility. The Terminal Services Agreement has an initial term of 12 months and automatically renews for additional terms of 6 months. The parties may terminate the Terminal Services Agreement upon 45 days’ written notice. Rental fees received from LEH under the Terminal Services Agreement are reflected within tank rental revenue in our consolidated statements of operations.

 

Loan and Security Agreement. In August 2016, BDPL entered into a loan and security agreement with LEH as evidenced by a promissory note in the original principal amount of $4.0 million (the “LEH Loan Agreement”). The LEH Loan Agreement matures in August 2018, and accrues interest at rate of 16.00%. Under the LEH Loan Agreement, BDPL will make payments of $500,000 per year from the annual payment received from FLNG pursuant to a Master Easement Agreement between BDPL and FLNG dated December 11, 2013. A final balloon payment is due at maturity.

 

The proceeds of the LEH Loan Agreement were used for working capital. There are no financial maintenance covenants associated with the LEH Loan Agreement. The LEH Loan Agreement is secured by: (i) the assignment of payments received by BDPL from FLNG under the Master Easement Agreement and (ii) certain real estate assets of BDPL. Outstanding principal and interest less associated debt issue costs owed to LEH under the LEH Loan Agreement are reflected in long-term debt, related party, current portion and long-term debt, related party, net of current portion in our consolidated balance sheets.

 

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with LEH in the original principal amount of $1,797,172 (the “LEH Note”). The LEH Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the LEH Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to LEH under the LEH Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

 

Ingleside Crude, LLC (“Ingleside”). We are party to an Amended and Restated Tank Lease Agreement and a Promissory Note with Ingleside. Ingleside is a related party of LEH and Jonathan Carroll.

 

Amended and Restated Tank Lease Agreement. Pursuant to an Amended and Restated Tank Lease Agreement with Ingleside, we lease petroleum storage tanks to meet periodic, additional storage needs. The Amended and Restated Tank Lease Agreement had an initial term of 30 days with automatic 30-day renewal periods. The parties may terminate the tank lease agreement upon 30 days’ written notice. Renatal fees owed to Ingleside under the tank lease agreement are reflected within accounts payable, related party in our consolidated balance sheets. Amounts expensed as rental fees to Ingleside under the Amended and Restated Tank Lease Agreement are reflected within refinery operating expenses in our consolidated statements of operations.

 

Promissory Note. In September 2016, Blue Dolphin entered into a promissory note with Ingleside in the original principal amount of $679,385 (the “Ingleside Note”). The Ingleside Note accrues interest, compounded annually, at a rate of 8.00%. The principal amount and any accrued but unpaid interest are due and payable in January 2018. Under the Ingleside Note, prepayment, in whole or in part, is permissible at any time and from time to time, without premium or penalty. Outstanding principal and interest owed to Ingleside under the Ingleside Note are reflected in long-term debt, related party, net of current portion in our consolidated balance sheets.

 

Jonathan Carroll. We are party to Guaranty Fee Agreements and a Promissory Note with Jonathan Carroll. Jonathan Carroll is Chairman of the Board, Chief Executive Officer, and President of Blue Dolphin.