BLUE DOLPHIN ENERGY CO - Annual Report: 2016 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

 

FORM 10-K

(Mark One)

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2016

 or

 

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from             to           

Commission File No. 0-15905

 

BLUE DOLPHIN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

 

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

 

801 Travis Street, Suite 2100 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

 (713) 568-4725

Registrant’s telephone number, including area code

 

Securities registered pursuant to Section 12(b) of the Act: None

 

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, par value $0.01 per share

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

 

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

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☑

 

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

 

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☐ Smaller Reporting Company ☑

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

 

The aggregate market value of shares of common stock held by non-affiliates of the registrant as of June 30, 2016 was $8,000,248 based on the number of shares of common stock held by non-affiliates and the last reported sale price of the registrant's common stock on June 30, 2016.

 

Number of shares of common stock, par value $0.01 per share outstanding at March 31, 2017: 10,474,714

 

INTRODUCTION

 

This Annual Report for the fiscal year ended December 31, 2016 (this “Annual Report”) is a document that U.S. public companies file with the Securities and Exchange Commission (“SEC”) every year. Part I of the Annual Report provides a general overview of our business, including relevant risk factors. Part II of the Annual Report contains financial information and management’s discussion and analysis of our financial condition and results of operations. We hope investors will find it useful to have all this information in a single document.

 

Within this Annual Report, “Blue Dolphin,” “we,” “our,” and “us” are used interchangeably to refer to Blue Dolphin Energy Company or to Blue Dolphin Energy Company and its subsidiaries, as appropriate to the context. Information in this Annual Report is current as of the filing date, unless otherwise specified.

 

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

 

In this Annual Report, and from time to time throughout the year, we share our expectations for our future performance. These forward-looking statements include statements about our business plans; our expected financial performance, including the anticipated effect of strategic actions; previously reported material weakness in our internal control over financial reporting; economic, political and market conditions; and other factors that could affect our future results of operations or financial condition, including, without limitation, statements under the sections entitled “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part I, Item 3. Legal Proceedings,” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Any statements we make that are not matters of current reportage or historical fact should be considered forward-looking. Such statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “will,” and similar expressions. By their nature, these types of statements are uncertain and are not guarantees of our future performance. Our forward-looking statements represent our estimates and expectations at the time of disclosure. However, circumstances change constantly, often unpredictably, and investors should not place undue reliance on these statements. Many events beyond our control will determine whether our expectations will be realized. We disclaim any current intention or obligation to revise or update any forward-looking statements, or the factors that may affect their realization, whether considering new information, future events or otherwise, and investors should not rely on us to do so. In accordance with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, “Part I, Item 1A. Risk Factors” within this Annual Report explains some of the important factors that may cause actual results to be materially different from those that we anticipate.

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

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 Annual Report:

 

TABLE OF CONTENTS

 

PART I		6
ITEM 1.	BUSINESS	6
ITEM 1A.	RISK FACTORS	18
ITEM 1B.	UNRESOLVED STAFF COMMENTS	28
ITEM 2.	PROPERTIES	29
ITEM 3.	LEGAL PROCEEDINGS	30
ITEM 4.	MINE SAFETY DISCLOSURES	31
PART II		32
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	32
ITEM 6.	SELECTED FINANCIAL DATA	32
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	51
	Report of Independent Registered Public Accounting Firm
	Consolidated Balance Sheets	52
	Consolidated Statements of Operations	53
	Consolidated Statements of Stockholders’ Equity	54
	Consolidated Statements of Cash Flows	55
	Notes to Consolidated Financial Statements	56
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	57
ITEM 9A.	CONTROLS AND PROCEDURES	89
ITEM 9B.	OTHER INFORMATION	90
PART III		91
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	91
ITEM 11.	EXECUTIVE COMPENSATION	95
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	97
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	98
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	101
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	102
ITEM 16.	FORM 10-K SUMMARY	102
SIGNATURES		108

PART I

ITEM 1.  BUSINESS

 

Overview

 

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 in Nixon, Texas (the “Nixon Facility”). As part of our refinery business segment, we also conduct petroleum storage and terminaling operations under third-party lease agreements at the Nixon Facility. Under our pipeline transportation business segment, we own pipeline assets and have leasehold interests in oil and gas wells. Our pipeline transportation business segment represented less than 1% of total revenue for the years ended December 31, 2016 and 2015.We maintain a website at http://www.blue-dolphin-energy.com. Information on or accessible through our website is not incorporated by reference in or otherwise made a part of this Annual Report.

 

Structure and Management

 

We were 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 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 “Part II, Item 8. Financial Statements and Supplementary Data– Note (8) Related Party Transactions,” “Note (10) Long-Term Debt, Net,” and “Note (20) Commitments and Contingencies – Financing Agreements” and “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence – Related Party Transactions” 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 2. Properties” of this Annual Report for additional information regarding our operating subsidiaries.)

 

Operating Risks – Going Concern

 

Management has determined that certain factors raise substantial doubt about our ability to continue as a going concern. 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. For the year ended December 31, 2016, execution of our business strategy was negatively impacted by several factors, including:

 

 

 

 

 

 

 

We are taking aggressive actions to improve operations and liquidity by: (i) continuing with Nixon Facility capital improvements, including upgrading the refinery’s heat exchangers and increasing petroleum storage tank capacity, (ii) increasing military jet fuel sales and low-sulfur diesel exports to Mexico, (iii) restructuring customer contracts as they come up for renewal to incorporate minimum sales volumes, (iv) working to secure a long-term crude oil and condensate supply arrangement, (v) exploring alternative funding sources for crude oil and condensate purchases, and (vi) seeking additional financing to meet ongoing liquidity needs. There can be no assurance that our plan will be successful or that we will be able to obtain additional financing on commercially reasonable terms or at all.

 

For additional disclosures related to our agreements and the contract-related dispute with GEL, financial covenant violations, and risk factors that could materially affect our future results of operations, refer to the following sections within this Annual Report:

 

 

 

 

Refining Industry Overview

 

Crude oil refining is the process of separating the hydrocarbons present in crude oil into usable or refined petroleum products such as naphtha, diesel, jet fuel and other products. Crude oil refining is primarily a margin-based business where both crude oil and refined petroleum products are commodities with prices that can fluctuate independently for short periods due to supply, demand, transportation and other factors. To increase profitability, or improve margins, it is important for a crude oil refinery to maximize the yields of higher value petroleum products and to minimize the costs of feedstocks and operating expenses. There are also several operational efficiencies that can be deployed to improve margins. These include selecting the appropriate crude oil or condensate to fulfill anticipated product demand, increasing the amount and value of refined petroleum products processed from the crude oil or condensate, reducing downtime for maintenance, repair and investment, developing valuable by-products or production inputs out of materials that are typically discarded, and adjusting utilization rates.

 

A refinery's product slate depends on the refinery's configuration and the type of crude oil and/or condensate being refined, and can be adjusted based on market demand. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined petroleum products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined petroleum products. The effect of changes in crude oil prices on a refinery’s results of operations depends, in part, on how quickly and how fully refined petroleum products prices adjust to reflect these changes.

 

Our Primary Operating Asset

 

Nixon Facility

 

The Nixon Facility, which is located on a 56-acre site in Nixon, Texas, has aggregate crude oil throughput capacity of 15,000 bpd. The Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, and related loading and unloading facilities and utilities. At December 31, 2016, the refinery had approximately 842,000 bbls of crude oil, condensate, and refined petroleum product storage capacity in 27 tanks. We are currently constructing an additional 256,000 bbls of petroleum storage capacity at the site. When construction is complete, total crude oil, condensate, and refined petroleum product storage capacity at the Nixon Facility will exceed 1,000,000 bbls.

 

A regional electric cooperative supplies electrical power to the Nixon Facility. Fuel gas (LPGs) that are produced at the Nixon Facility are primarily used as fuel within the refinery. In addition, small amounts of propane are occasionally acquired for use in starting-up the Nixon Facility.

 

Nixon Facility Process Summary

 

The Nixon Facility is considered a “topping unit” because it is primarily comprised of a crude distillation unit, the first stage of the crude oil refining process. The Nixon Facility’s current level of complexity allows us to refine crude oil and condensate into finished and intermediate petroleum products. The below diagram represents a high-level overview of the current crude oil and condensate refining process at the Nixon Facility.

 

 Example represents a simplified plant configuration. The specific configuration will vary based on various market and operational factors.

 

 

Turnaround and Refinery Reliability

 

We are committed to the safe and efficient operation of the Nixon Facility. Turnarounds are used to repair, restore, refurbish or replace refinery equipment such as vessels, tanks, reactors, piping, rotating equipment, instrumentation, electrical equipment, heat exchangers and fired heaters. Typically, a refinery undergoes a major facility turnaround every three to five years. Since the Nixon Facility is still in the recommissioning phase, one or more of the units may require additional unscheduled downtime for unanticipated maintenance or repairs that are more frequent than our scheduled turnarounds.

 

Crude Oil and Condensate Supply

 

Historically, we purchased light crude oil and condensate for the Nixon Facility from GEL pursuant to the Crude Supply Agreement. The Crude Supply Agreement automatically renews for successive one-year terms until August 2019 unless GEL provides us with notice of non-renewal at least 180 days prior to expiration of any renewal term. The parties are currently involved in a contract-related dispute. As a result, we ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Key Relationships – Relationship with Genesis and GEL” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” of this Annual Report for more information related to GEL and the Crude Supply Agreement.

 

In June 2016, we entered a month-to-month evergreen crude oil supply contract with a major integrated oil and gas company as back-up to the Crude Supply Agreement. We believe that adequate supplies of crude oil and condensate for the Nixon Facility will continue to be available to us from the alternate supplier. We are working to put a long-term crude supply agreement in place, however, our ability to purchase adequate supplies of crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.

 

The Nixon Facility processes light crude oil sourced from the Eagle Ford Shale. The crude oil and condensate is received at the Nixon Facility by truck and stored in tanks. The Nixon Facility’s property is crossed by a crude oil and condensate pipeline owned by Koch Pipeline Company. The pipeline represents a potential future opportunity to receive crude oil and condensate at the Nixon Facility, which could reduce trucking costs.

 

Products and Markets

 

Products

 

The Nixon Facility’s product slate can be adjusted based on market demand. We currently produce two finished products – jet fuel and low-sulfur diesel. We produce several intermediate products, including LPG, naphtha, HOBM, and AGO.

 

Markets

 

The Nixon Facility is in the Gulf Coast region of the U.S., which is represented by the Energy Information Administration as Petroleum Administration for Defense District 3 (“PADD 3”). Although our products are primarily sold in the U.S. within PADD 3, with the 2016 opening of the Mexican diesel market to private companies, we began selling low-sulfur diesel to customers that are exporting to Mexico. Jet fuel from the Nixon Facility is sold in nearby markets to wholesalers. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing.

 

Customers

 

Customers for our refined petroleum products include distributors, wholesalers and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms, in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of finished and intermediate petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (14) Concentration of Risk” of this Annual Report for disclosures related to significant customers.

 

Competition

 

Many of our competitors are substantially larger than us and are engaged on a national or international basis in many segments of the petroleum products business, including exploration and production, refining, transportation and marketing. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We compete primarily based on cost. Due to the low complexity of our simple “topping unit” refinery, we can be relatively nimble in adjusting our refined petroleum products slate because of changing commodity prices, market demand, and refinery operating costs.

 

Business Strategies

 

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

 

Capital and Efficiency Improvements

 

In 2015, we secured $35.0 million in 19-year financing to expand the Nixon Facility. During 2016, capital improvements at the Nixon Facility primarily related to construction of new petroleum storage tanks to add to existing petroleum storage tank capacity. In 2016, we completed construction of four new tanks, and began construction on several additional new tanks that will be completed in 2017. When expansion of the Nixon Facility is complete, total crude oil, condensate, and refined petroleum product storage capacity will exceed 1,000,000 bbls.

 

Overall improvements at the Nixon Facility will position us for long-term growth by: (i) having crude and product storage to support refinery throughput and future expansion of up to 30,000 bbls per day; (ii) increasing the processing capacity and complexity of the Nixon Facility for expanded refined product opportunities; and (iii) generating additional revenue from leasing product and crude storage to third parties.

 

Capital expenditures at the Nixon Facility are being funded primarily through borrowings under credit bank facilities that were secured in 2015. Capital expenditures as of the dates indicated were as follows:

	Years Ended December 31,
	2016	2015
Cash disbursements	$14,100,897	$11,370,993
Accounts payable(1)	2,286,082	873,665
	$16,386,979	$12,244,658

 

 

During 2016, capital improvements at the Nixon Facility primarily related to construction of new petroleum storage tanks to add to existing petroleum storage tank capacity. In 2016, we completed construction of four new tanks, and we began construction on several additional new tanks that will be completed in 2017. When expansion of the Nixon Facility is complete, total crude oil, condensate, and refined petroleum product storage capacity will exceed 1,000,000 bbls. (See “Part I, Item 8. Financial Statements and Supplementary Data – Note (10) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.)

 

Explore New Revenue Opportunities

 

In April 2016, private companies were authorized to participate in the Mexican diesel market, part of recent energy reforms in Mexico that opened the doors to private foreign investment. As a result, we began exporting low-sulfur diesel to Mexico via truck in the second quarter of 2016. We also began fulfilling heavy oil-based mud blendstock orders from new customers within PADD 3 by barge. Going forward, we will continue to explore ways to maximize refined petroleum product sales through new delivery mediums.

 

In addition to new delivery modes, we also began restructuring customer agreements as they come up for renewal. New pricing models with minimum volume requirements are expected to further improve revenue in 2017.

 

Pipeline Transportation

 

Our pipeline transportation operations involve the gathering and transportation of oil and natural gas for producers/shippers operating offshore near our pipelines, as well as leasehold interests in oil and natural gas properties, in the Gulf of Mexico. Our pipeline transportation operations represented less than 1% of total revenue for the years ended December 31, 2016 and 2015.

 

We recorded an impairment expense of $968,684 related to our pipeline assets at December 31, 2016. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor are being permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines. Our oil and gas properties had no production during the years ended December 31, 2016 and 2015. All leases associated with our oil and gas properties have expired, and our oil and gas properties were fully impaired in 2011.

 

Acquisition, Disposition and Restructuring Activities

 

We regularly engage in discussions with third-parties regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. However, we do not anticipate any material acquisition activity in the foreseeable future.

 

In 2013, the Board established a Master Limited Partnership (“MLP”) Conversion Special Committee to oversee a potential conversion of Blue Dolphin from a Delaware “C” corporation to a Delaware MLP. Due to a shift in market conditions over the past three years, the MLP Conversion Special Committee determined that a conversion in the foreseeable future would not be in the best interests of shareholders.

 

Insurance and Risk Management

 

Our operations are subject to significant hazards and risks inherent in crude oil and condensate refining operations and in the transportation and storage of crude oil and condensate, as well as finished and intermediate petroleum products. We have property damage and business interruption coverage at the Nixon Facility. Business interruption coverage is for 24 months from the date of the loss, subject to a deductible with a 45-day waiting period. Our property damage insurance has deductibles ranging from $5,000 to $500,000. In addition, we have a full suite of insurance policies covering workers’ compensation, general liability, directors’ and officers’ liability, environmental liability, and other business risks. These are supported by safety and other risk management programs. See also, “Part I, Item 1A. Risk Factors – Risks Related to Our Business” in this Annual Report.

 

Governmental Regulation

 

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

 

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

 

We cannot predict the extent to which additional environmental, health, and safety laws will be enacted in the future, or how existing or future laws will be interpreted with respect to our operations. Many environmental, health, and safety laws and regulations are becoming increasingly stringent. The cost of compliance with and governmental enforcement of environmental, health, and safety laws may increase in the future. We may be required to make significant capital expenditures or incur increased operating costs to achieve or sustain compliance with applicable environmental, health, and safety laws. This Governmental Regulation section should be read in conjunction with “Part I, Item 1A. Risk Factors” of this Annual Report, which discusses our expectations regarding future events based on currently available information.

 

Air Emissions

 

Toxic Air Pollutants. The federal Clean Air Act (the “CAA”) is a comprehensive law that regulates toxic air pollutants from stationary and mobile sources. Among other things, the law authorizes the Environmental Protection Agency (the “EPA”) to establish National Ambient Air Quality Standards to protect public health and public welfare and to regulate emissions of hazardous air pollutants. The CAA, as well as corresponding state laws and regulations regarding emissions of pollutants into the air, affect our crude oil and condensate processing operations and impact certain emissions sources located offshore. Under the CAA, facilities that emit volatile organic compounds (“VOCs”) or nitrogen oxides face increasingly stringent regulations.

 

Refineries, which are major stationary sources of Hazardous Air Pollutants (“HAPs”), have historically been high-visibility targets for enforcement by the EPA under the CAA. In 1995, the EPA implemented the National Standards for Hazardous Air Pollutants for petroleum refineries. These standards require petroleum refineries to meet emission standards reflecting the application of the maximum achievable control technology. The affected sources at petroleum refineries are defined to include all process vents, storage vessels, marine tank vessel loading operations, gasoline rack operations, equipment leaks, and wastewater treatment systems located at the refinery. To meet emission standards, we are required to obtain permits, as well as test, monitor, report, and implement control requirements.

 

In 2007, the EPA finalized a rule to reduce HAPs from mobile sources.  Mobile Source Air Toxics (“MSAT”) regulations established stringent new controls on gasoline, passenger vehicles, and gas cans to further reduce emissions of mobile source air toxics. The EPA has continued to adopt MSAT emission control programs to further reduce HAPs from mobile sources, including sulfur control requirements in gasoline and diesel transportation fuels. New sulfur control standards required most refineries to produce transportation fuels for highway use at or below 15 ppm sulfur for “on-road” diesel and 30 ppm sulfur for gasoline. “Off-road” diesel requirements were also reduced to 15 ppm sulfur in 2014. The Nixon Facility does not produce gasoline, and the facility ceased production of NRLM, a transportation-related diesel fuel product in 2014.  In 2014, the Nixon Facility began producing HOBM, a non-transportation lubricant blend product.  The shift in product slate from NRLM to HOBM was the result of the EPA’s new sulfur control requirements. “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s new sulfur control standards, and integration of such a desulfurization unit generally requires additional permitting and significant capital upgrades. We can produce and sell diesel with sulfur content levels above the EPA’s new sulfur control standards in the U.S. as a feedstock to other refineries and blenders and to other countries as a finished petroleum product.

 

In May 2016, the EPA took further steps to cut emissions of methane from the oil and gas industry by issuing three (3) final rules intended to curb emissions of methane, VOC’s, and air toxics from new, reconstructed and modified oil and gas sources, while providing greater certainty about CAA permitting requirements for the industry. The EPA also issued for public comment an Information Collection Request (“ICR”) to obtain extensive information instrumental for developing regulations to reduce methane emissions from existing oil and gas sources.

 

Greenhouse Gas Emissions. In 2007, the U.S. Supreme Court held in Massachusetts vs. EPA that emission of Greenhouse Gases (“GHGs”) may be regulated under the CAA. In 2009, the EPA published its findings that GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, presenting a potential danger to public health and the environment. By allowing the regulation of GHGs under the CAA, the EPA’s findings also indirectly impacted many other carbon-intensive industries, which would potentially become subject to federal New Source Review Prevention of Significant Deterioration (“PSD”) and Title V permitting requirements under the CAA (the “CAA Permitting Requirements”). 

 

In 2010, the EPA set GHG emissions thresholds to define when permits under the CAA Permitting Requirements are required for new and existing industrial facilities (the “2010 Tailoring Rule”). Emissions from small farms, restaurants, and all but the very largest commercial facilities are not covered by the 2010 Tailoring Rule. The 2010 Tailoring Rule established a schedule that: (i) initially focused on the largest stationary sources with the most CAA permitting experience, (ii) then expanded to cover the largest stationary sources of GHG that may not have been previously covered by the CAA for other pollutants, and (iii) finally described the EPA’s plan for any additional steps in this process. Without this tailoring rule, the lower emissions thresholds would have taken effect automatically for GHGs in 2011, leading to dramatic increases in the number of required permits. The EPA implemented the 2010 Tailoring Rule in phases.

 

In May 2016, the EPA updated New Source Performance Standards (“NSPS”) by setting emission limits for methane, covering additional sources, such as hydraulically fractured oil wells, and requiring owners/operators to find and repair leaks. The EPA also updated the Source Determination rules to clarify when multiple pieces of equipment and activities must be deemed a single source when determining whether major source permitting programs apply.

 

Although we are not currently subject to reporting requirements under GHG-related regulations, the future adoption of any regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the Nixon Facility could require us to incur significant costs and expenses or changes in operations, which could adversely affect our operations and financial condition.

 

Renewable Fuels

 

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA issued Renewable Fuels Standards (“RFS”) that require the blending of biofuels into transportation fuel. Since the compliance mechanism for RFS - Renewable Identification Numbers (“RINs”) – would have created a burden on the Nixon Facility related to its NRLM production through 2014, we applied for an extension of the temporary exemption afforded small refineries through December 31, 2010 under the CAA Section 211(o)(9)(B). In 2014, the EPA granted the Nixon Facility a small refinery exemption from RFS requirements for 2013 and 2014. We ceased production of NRLM, a transportation-related diesel fuel product in 2014.  In 2014, we began producing HOBM, a non-transportation lubricant blend product.

 

Hazardous Waste

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes strict, joint and several liability on responsible parties with uncontrolled or abandoned hazardous waste sites, as well as accidents, spills, and other emergency releases of pollutants and contaminants into the environment. The law authorizes two kinds of response actions: (i) short-term removals, where actions may be taken to address releases or threatened releases requiring prompt response, and (ii) long-term remedial response actions, that permanently and significantly reduce the dangers associated with releases or threats of releases of hazardous substances that are serious, but not immediately life threatening. As of the filing of this Annual Report, neither we nor any of our predecessors have been designated as a potentially responsible party under CERCLA or a similar state statute.

 

The Resource Conservation and Recovery Act (“RCRA”) and comparable state and local laws impose requirements related to the handling, storage, treatment and disposal of solid and hazardous wastes. Our refining operations generate petroleum product wastes, solid wastes, and ordinary industrial wastes, such as from paint and solvents, that are regulated under RCRA and state law. Certain wastes generated by the Nixon Facility are currently exempt from regulation as hazardous wastes, but are subject to non-hazardous waste regulations. In the future, these wastes could be designated as hazardous wastes under RCRA or other applicable statutes and therefore may become subject to more rigorous and costly requirements.

 

The Nixon Facility has been used for refining activities for many years. Although prior owners and operators may have used operating and waste disposal practices that were standard in the industry at the time, petroleum hydrocarbons and various wastes may have been released on or under the Nixon Facility site. A 2008 third-party environmental study determined that petroleum hydrocarbon and VOC concentrations were below Tier 1 protective concentration levels (“PCLs”). However, RCRA-8 metals were found to be above Tier 1 PCLs. An additional third-party study determined that metal concentrations from the soil would not leach beyond groundwater concentrations exceeding their respective PCLs. As a result, groundwater resources would not be threatened and no further reporting was required.

 

Water Discharges

 

Stormwater from the Nixon Facility is tested and discharged pursuant to applicable stormwater permits. Process wastewater from the Nixon Facility is tested and discharged to a nearby municipal treatment facility pursuant to applicable process wastewater permits. Wastewater from our offshore facilities, including our oil and natural gas pipelines and anchor platform, are tested and discharged pursuant to applicable produced water permits.

 

Spill Prevention and Control

 

The federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. These laws affect our crude oil and condensate processing operations and petroleum storage and terminaling operations, as well as our pipeline, facilities, and exploration and production assets. The CWA prohibits the discharge of pollutants into U.S. waters except as authorized by the terms of a permit issued by the EPA or a state agency with delegated authority. Spill prevention, control, and countermeasure requirements mandate the use of structures, such as berms and other secondary containment, to prevent hydrocarbons or other pollutants from reaching a jurisdictional body of water in the event of a spill or leak. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA or analogous state laws and regulations.

 

The EPA covers inland oil spills. In 2015, the EPA published a final rule expanding the definition of “Waters of the United States” under the CWA. The final rule did not expand federal jurisdiction. However, the final rule identified waters that are specifically excluded from jurisdiction, including, among others, depressions incidental to mining or construction that may become filled with water, puddles, groundwater, and stormwater control features constructed to convey, treat, or store stormwater on dry land. See “Offshore Safety and Environmental Oversight” within this governmental regulation section for information on oil spills that occur in coastal waters.

 

Offshore Safety and Environmental Oversight

 

In addition to the CAA, our pipeline, exploration and production assets are also subject to the requirements of the Outer Continental Shelf Lands Act (the “OCSLA”). The OCSLA is administered by the Bureau of Ocean Energy Management (the “BOEM”) and the Bureau of Safety and Environmental Enforcement (the “BSEE”) and the Office of Natural Resources Revenue (“ONRR”). The BOEM manages the nation's offshore resources in an environmentally and economically responsible way, including leasing, plan administration, environmental studies, National Environmental Policy Act analysis, resource evaluation, economic analysis, and the Renewable Energy Program. The BSEE enforces safety and environmental regulations, including permitting and research, inspections, offshore regulatory programs, oil spill response, and training and environmental compliance functions. Regarding oil spill response, the BSEE has partnered with the U.S. Coast Guard (“USCG”). In the event of an oil spill, the BSEE is responsible for monitoring and directing all efforts related to securing the source of the spill and re-establishing control over the facility. The USCG is responsible for monitoring and directing all efforts to mitigate a spill’s impact on the water, shoreline, or economic centers that could be impacted, as well as recovering any oil that has spilled. In recent years, the BOEM and the BSEE have been more aggressive in proposing and implementing several reforms to offshore oil and gas regulations.

 

Spill Liability. The Oil Pollution Act of 1990 (the “OPA”) and the CWA, in connection with the OCSLA, impose liability on owners or operators of vessels and facilities that discharge oil into the navigable waters of the U.S., adjoining shorelines, waters of the contiguous zone, or when the discharge may affect natural resources of the U.S. With limited exceptions, responsible parties are liable for all removal costs and damages arising from oil spills. Damages may include: injury or economic losses resulting from destruction of real or personal property, damages or loss of use of natural resources used for subsistence, lost tax revenue, royalties, rents, or net profit shares suffered by federal, state, or local governments due to injury to real or personal property, lost profits or impaired earning power because of injury to real or personal property or natural resources, and the net costs of providing increased or additional public services during or after removal activities.

 

In 2015, the BOEM increased the offshore limit of liability for damages under the OPA from $75 million to $133.65 million, plus all clean-up costs, to reflect the significant increase in the Consumer Price Index. The onshore facilities limit of liability for damages under the OPA is $350 million plus all clean-up costs. A party cannot take advantage of the liability limits if the spill is caused by gross negligence or willful misconduct or resulted from a violation of federal safety, construction or operating regulations. If a party fails to report a spill or cooperate in the clean-up, liability limits do not apply.

 

The OPA requires responsible parties to provide proof of financial responsibility for potential spills. The evidence of financial responsibility amount required is $35 million for certain types of offshore facilities located seaward of the seaward boundary of a state, including properties used for oil transportation. The BOEM’s 2015 regulatory change did not affect the ongoing required coverage amount. We currently maintain the statutory $35 million coverage.

 

Spill Response. Pursuant to the OPA, the National Oil and Hazardous Substances Pollution Contingency Plan, more commonly called the National Contingency Plan, provides a blueprint for responding to both oil spills and hazardous substance releases. The National Contingency Plan requires, among other things, that responsible parties have an oil spill response plan in place. We have an oil spill response plan in place.

 

Decommissioning Requirements. To cover the various obligations of lessees and rights-of-way holders operating in federal waters of the Gulf of Mexico, the BOEM generally requires that lessees and rights-of-way holders demonstrate financial strength and reliability per regulations or post bonds or other acceptable assurances that such obligations will be satisfied, unless the BOEM exempts the lessee or rights-of-way holder from such financial assurance requirements. Such obligations include the cost of plugging and abandoning wells and decommissioning and removing platforms and pipelines at the end of production or service activities. Once plugging and abandonment work has been completed, the collateral backing the financial assurance is released by the BOEM.

 

In 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking outlining proposed changes to financial assurance requirements to modernize financial assurance and risk management and better address potential costs and liabilities of offshore energy development. Part of the Advanced Notice of Proposed Rulemaking includes the BOEM revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit based model. In July 2016, the BOEM issued NTL No. 2016– N01, Notice to Lessees and Operators of Federal Oil and Gas, and Sulfur Leases, and Holders of Pipeline Right-of-Way and Right-of-Use and Easement Grants in the Outer Continental Shelf—Requiring Additional Security (“NTL 2016-N01”). NTL 2016-N01 outlines new criteria that will be used to determine the financial ability of a lessee, right-of-way holder, or right-of-use and easement holder to carry out its obligations, and addresses the possibility of individually tailoring a plan to enable the lessee, right-of-way holder, or right-of-use and easement holder to use one or more forms of security other than surety bonds and pledges of treasury securities and/or to phase-in compliance with the additional security requirement pursuant to such a plan. Lessees will no longer be granted waivers from the additional security obligations, and the BOEM is discontinuing the policy of considering the combined strength and reliability of co-lessees when determining a lessee’s additional security requirements. NTL 2016-N01 became effective in September 2016. In 2016, the BSEE issued NTL 2016-N03, Reporting Requirements for Decommissioning Expenditures on the OCS (“NTL 2016-N03”). Issued in April 2016, NTL 2016-N03 provides guidance and clarification regarding submission of certified decommissioning cost expenditure summaries following permanent plugging of any well, removal of any platform or other facility, and clearance of any site.

 

The BOEM is requiring that we provide additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. We are currently working with the BOEM to develop a tailored plan to address the financial assurance requirements, particularly considering existing permit requests to abandon-in-place certain of our pipeline assets. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. At December 31, 2016 and 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM.

 

Offshore Safety. In 2010, the BSEE issued The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system (“SEMS”).  Revisions to SEMS (“SEMS II”), which added several requirements to the original SEMS, became effective in 2013. The purpose of SEMS II is to reduce human and organizational errors as root causes of work-related accidents and offshore spills, develop protocols as to who at the facility has the ultimate operational safety and decision-making authority, and establish procedures to provide all personnel with “stop work” authority. SEMS II must be periodically audited by an independent third party auditor approved by the BSEE. We have a SEMS II plan in place.

 

Health, Safety and Maintenance

 

We are subject to several federal and state laws and regulations related to the health and safety of workers pursuant to the Occupational Safety and Health Act of 1970. These laws and regulations are administered by the Occupational Safety and Health Administration (the “OSHA”) and, in states not participating in OSHA-approved state safety plans, comparable state regulatory bodies.

 

Our refinery operations are also subject to OSHA process safety management regulations. In 2007, the OSHA launched the National Emphasis Program for Petroleum Refineries (the “RNEP”), which requires that refineries be inspected for compliance with process safety management regulations. Under RNEP, The Nixon Facility is subject to inspections under RNEP. Inspections may last from two to six months, including one to three months onsite. Inspectors primarily focus on process safety management implementation and recordkeeping.

 

The Nixon Facility was inspected by OSHA in 2013 and again in June 2016. Following the 2013 inspection, we were assessed a civil penalty of $38,500. Following the 2016 inspection, we were assessed a civil penalty of $6,006. Citations issued by OSHA primarily related to failure to comply with documentation and notice posting requirements.

 

We operate a comprehensive safety, health and security program, with participation by personnel at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely monitor our programs and consider improvements in our management systems.

 

Intellectual Property

 

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

 

Personnel

 

We rely on the services of LEH pursuant to the Operating Agreement to manage our property and the property of our subsidiaries, including the Nixon Facility, in the ordinary course of business. LEH provides us with the following services, among others, under the Operating Agreement:

 

 

 

See “Part II, Item 8. Financial Statements and Supplementary Data - Note (8), Related Party Transactions” of this Annual Report for additional disclosures related to LEH.

 

Available Information

 

We are subject to the informational requirements of the Exchange Act. We file financial and other information with the SEC as required, including but not limited to, proxy statements on Schedule 14A, Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during the hours of 10:00 a.m. to 3:00 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at http:///www.sec.gov that contains reports, proxy information and information statements, and other information regarding issuers, including us, that file electronically with the SEC.

 

We also make our SEC filings available through our website (http://www.blue-dolphin-energy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

ITEM 1A.  RISK FACTORS

 

An investment in our Common Stock involves risks. In addition to the other information in this Annual Report and our other filings with the SEC, you should carefully consider the following risk factors in evaluating us and our business. The risks described below are not the only risks we face. Additional risks and uncertainties not specified herein, not currently known to us, or currently deemed to be immaterial may also materially adversely affect our business, financial condition, operating results and/or cash flows.

 

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

 

Risks Related to Our Business and Industry

 

We may not have sufficient liquidity to sustain operations because of net losses, working capital deficits, and other factors, including an adverse change in our relationship with Genesis and GEL, crude supply issues, and financial covenant defaults in secured loan agreements.

 

For the year ended December 31, 2016, we reported a net loss of $15,767,448, or a loss of $1.51 per share, compared to net income of $4,403,239, or income of $0.42 per share, for the year ended December 31, 2015. This represented a decrease of 1.93 per share between the periods. We had cash and cash equivalents and restricted cash (current portion) of $1,152,628 and $3,347,835, respectively, at December 31, 2016. Comparatively, we had cash and cash equivalents and restricted cash (current portion) of $1,853,875 and $3,175,299, respectively, at December 31, 2015.

 

We had a working capital deficit of $37,812,263 at December 31, 2016 compared to a working capital deficit of $598,807 at December 31, 2015. The significant increase in working capital deficit between the periods primarily related to reclassification of secured long-term debt (and the related debt issue costs) with Sovereign to the current portion within long-term debt. Excluding long-term debt, we had a working capital deficit of $6,099,927 at December 31, 2016. Comparatively, we had a working capital deficit of $598,807 at December 31, 2015. This represented a decrease in working capital of $5,501,120 between the periods. The decrease in working capital was primarily the result of sustaining net losses in 2016 compared to net income in 2015. Net losses in 2016 resulted from lower margins on refined petroleum products, lower refinery throughput and significant refinery downtime, higher refinery operating expenses, and income tax expense. Margins on refined petroleum products decreased primarily because of lower crack spreads.

 

We are currently in a contract-related dispute with GEL. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved. As a result of the contract-related dispute, we ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier. As a result, we currently do not have a long-term crude supply agreement in place. We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. (Within this “Item 1A. Risk Factors” section, see also “Risks Related to Our Refining Operations” for a discussion of risks related to our operations being dependent on our relationship with Genesis and GEL.)

 

 

At December 31, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign. Consequently, Sovereign is permitted to 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. Although Sovereign waived the financial covenant defaults as of December 31, 2016, the debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2016 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. (Within this “Item 1A. Risk Factors” section, see also “Risks Related to Our Business and Industry” for a discussion of risks related to our financial covenant defaults with Sovereign.)

 

We are currently working to improve our operating performance and our cash, liquidity and financial position. This includes: executing on our business strategies to improve operating performance, exploring alternative funding sources for the purchase of crude oil and condensate, secure new financing to meet ongoing liquidity needs, attempting to negotiate alternative payment terms with creditors, obtaining waivers for financial covenant violations, and pursuing the sale of non-strategic surplus land. If we are unable to generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to acquisition of crude oil and condensate to operate the Nixon Facility, repayment of debt obligations, and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. In addition, we continue to utilize capital to reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. Our liquidity will affect our ability to satisfy any of these needs.

 

The dangers inherent in oil and gas operations could expose us to potentially significant losses, costs or liabilities and reduce our liquidity.

 

Oil and gas operations are inherently subject to significant hazards and risks. These hazards and risks include, but are not limited to, fires, explosions, ruptures, blowouts, spills, third-party interference and equipment failure, any of which could result in interruption or termination of operations, pollution, personal injury and death, or damage to our assets and the property of others. These risks could harm our reputation and business, result in claims against us, and have a material adverse effect on our results of operations and financial condition.

 

The geographic concentration of our assets creates a significant exposure to the risks of the regional economy and other regional adverse conditions.

 

Our primary operating asset, the Nixon Facility, is in Nixon, Texas in the Eagle Ford Shale and we market our refined petroleum products in a single, relatively limited geographic area. In addition, our onshore facilities assets are in Freeport, Texas, and all our pipelines, offshore facilities and oil and gas properties are located within the Gulf of Mexico. As a result, our operations are more susceptible to regional economic conditions than our more geographically diversified competitors. Any changes in market conditions, unforeseen circumstances, or other events affecting the area in which our assets are located could have a material adverse effect on our business, financial condition, and results of operations. These factors include, among other things, changes in the economy, weather conditions, demographics, and population.

 

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

 

The refining industry is highly competitive.  Our refining operations compete with domestic refiners and marketers in PADD 3 (Gulf Coast), domestic refiners in other PADD regions, and foreign refiners that import products into the U.S. Certain of our competitors have larger, more complex refineries and may be able to realize higher margins per barrel of production. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain all of our feedstocks from a single supplier. Because of their integrated operations and larger capitalization, larger, more complex refineries may be more flexible in responding to volatile industry or market conditions, such as crude oil and other feedstocks supply shortages or commodity price fluctuations.  If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers.

 

 

Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.

 

Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.

 

In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations, or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. Expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition, and profitability.

 

The Nixon Facility operates under several federal and state permits, licenses, and approvals with terms and conditions that contain a significant number of prescriptive limits and performance standards. These permits, licenses, approvals, limits, and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities, and accordingly our financial performance.

 

We are subject to strict laws and regulations regarding personnel and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

 

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to personnel and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.

 

Our insurance policies may be inadequate or expensive.

 

Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts more than our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience insurable events, we may experience an increase in annual premiums, a limit on coverage, or loss of coverage. Inadequate insurance or loss of coverage could have a material adverse effect on our business, financial condition, and results of operations.

 

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

 

Jonathan P. Carroll, our Chief Executive Officer, President, Assistant Treasurer and Secretary, is also a majority owner of LEH. LEH owns approximately 81% of our Common Stock, and, pursuant to the Operating Agreement, manages and operates all our properties. LEH and Mr. Carroll have significant influence over matters such as the election of our Board of Directors (the “Board”), control over our business, policies and affairs and other matters submitted to our stockholders. LEH and Mr. Carroll are entitled to vote the Common Stock owned by LEH in accordance with its interests, which may be contrary to the interests of other stockholders. LEH has interests that may differ from the interests of other stockholders and, as a result, there is a risk that important business decisions will not be made in the best interest of some of our stockholders.

 

LEH and its affiliates are not limited in their ability to compete with us and are not obligated to offer us business opportunities. We believe that the transactions and agreements that we have entered with LEH and its affiliates are on terms that are at least as favorable as could reasonably have been obtained at such time from third-parties. However, these relationships could create, or appear to create, potential conflicts of interest when our Board is faced with decisions that could have different implications for us and LEH or its affiliates. The appearance of conflicts, even if such conflicts do not materialize, might adversely affect the public’s perception of us, as well as our relationship with other companies and our ability to enter new relationships in the future, which may have a material adverse effect on our ability to do business.

 

We are in violation of certain financial covenants in secured loan agreements with Sovereign, and our failure to comply could materially and adversely affect our operating results and our financial condition.

 

At December 31, 2016, we were in violation of certain financial covenants in secured loan agreements with Sovereign. Consequently, Sovereign is permitted to 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 December 31, 2016. However, $31,680,911 of debt associated with these loans was classified within the current portion of long-term debt on our consolidated balance sheet at December 31, 2016, due to the uncertainty of our ability to meet the financial covenants in the future.

 

There can be no assurance that: (i) our assets or cash flow would be sufficient to fully repay borrowings under our outstanding long-term debt, either upon maturity or if accelerated, (ii) we would be able to refinance or restructure the payments on the long-term debt, and/or (iii) Sovereign will provide future waivers of covenant defaults. If we fail to comply with financial covenants associated with certain of our long-term debt and such failure is not cured or waived, then Sovereign may exercise any rights and remedies available under the loan agreement(s). Any such action by Sovereign would have a material adverse effect on our financial condition and ability to continue as a going concern. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (10), Long-Term Debt, Net and Note (21) Subsequent Events” for additional disclosures related to our long-term debt and financial covenant violations.)

 

Our ability to use net operating loss (“NOL”) carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

 

Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

 

Blue Dolphin experienced ownership changes in 2005 in connection with a series of private placements, and in 2012 because of a reverse acquisition. The 2012 ownership change limits our ability to utilize NOLs following the 2005 ownership change that were not previously subject to limitation. Limitations imposed on our ability to use NOLs to offset future taxable income could cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect, and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes. NOLs generated after the 2012 ownership change are not subject to limitation.

 

At December 31, 2016 and 2015, we had $0 and approximately $8.3 million, respectively, in deferred tax assets. As of each reporting date, management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the three-year period ended December 31, 2016. 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 full valuation allowance against the deferred tax assets as of December 31, 2016.

 

Terrorist attacks, cyber-attacks, threats of war, or actual war may negatively affect our operations, financial condition, results of operations, and cash flows.

 

Energy-related assets in the U.S. may be at a greater risk for future terrorist attacks than other potential targets. A direct attack on our assets or assets used by us could have a material adverse effect on our operations, financial condition, results of operations, and cash flows. In addition, any terrorist attack in the U.S. could have an adverse impact on energy prices, including prices for crude oil and refined petroleum products, and refining margins. Disruption or significant increases in energy prices could result in government imposed price controls. While we currently maintain some insurance that provides coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.

 

Our operations are dependent on our technology infrastructure, which includes a data network, telecommunications system, internet access, and various computer hardware equipment and software applications. Our technology infrastructure is subject to damage or interruption from several potential sources, including natural disasters, software viruses or other malware, power failures, cyber-attacks, and/or other events. To the extent that our technology infrastructure is under our control, we have implemented measures such as virus protection software and emergency recovery processes to address identified risks. However, there can be no assurance that a security breach or cyber-attack will not compromise confidential, business critical information, cause a disruption in our operations, or harm our reputation, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Risks Related to Our Refining Operations

 

Management has determined that there is, and the report of our independent registered public accounting firm expresses, substantial doubt about our ability to continue as a going concern.

 

Our auditors, UHY LLP, have indicated in their report on our financial statements for the year ended December 31, 2016, that conditions exist that raise substantial doubt about our ability to continue as a going concern due to recurring losses from operations and the substantial decline in working capital. A “going concern” opinion could impair our ability to finance our operations through the sale of equity, incurring debt, or other financing alternatives. Our ability to continue as a going concern will depend upon improved operating margins, the most significant driver of which is crack spreads, the availability and terms of financing for working capital to operate the Nixon Facility, purchase crude oil and condensate, and fund capital expenditures, and resolution of the contract-related dispute with GEL.  If we are unable to achieve these goals, our business would be jeopardized and we may not be able to continue.

 

Refining margins are volatile, and a reduction in refining margins will adversely affect the amount of cash we will have available for working capital.

 

Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. Our financial results are primarily affected by the relationship, or margin, between our refined petroleum product sales prices and our crude oil and condensate costs. Our crude oil and condensate acquisition costs and the prices at which we can ultimately sell our refined petroleum products depend upon numerous factors beyond our control.

 

The prices at which we sell refined petroleum products are strongly influenced by the commodity price of crude oil. If crude oil prices increase, our “refinery operations” business segment margins will fall unless we can pass along these price increases to our wholesale customers. Increases in the selling prices for refined petroleum products typically trail the rising cost of crude oil and may be difficult to implement when crude oil costs increase dramatically over a short period.

 

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

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Our future success depends on our ability to acquire sufficient levels of crude oil on favorable terms to operate the Nixon Facility.

 

Operation of the Nixon Facility depends on our ability to purchase adequate crude supplies on favorable terms. We are currently involved in a contract-related dispute with GEL related to the Crude Supply Agreement. In connection with this dispute, GEL significantly under-delivered crude oil and condensate to the Nixon Facility during 2016 resulting in 59 days of refinery downtime. To mitigate the impact of GEL’s disruption of crude Supply to the Nixon Facility, we entered a month-to-month evergreen crude oil supply contract with a major integrated oil and gas company in June 2016, as back-up to the Crude Supply Agreement. We ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier. We believe that adequate supplies of crude oil and condensate for the Nixon Facility will continue to be available to us from the alternate supplier. We are working to put a long-term crude supply agreement in place, however, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.

 

We are pursuing alternative sources to finance crude oil and condensate acquisition costs, including commodity sale and repurchase programs, inventory financing, debt financing, equity financing, or other means. We may not be successful in consummating suitable financing transactions in the time required or at all, securing financing on terms favorable to us, or obtaining crude oil and condensate at the levels needed to earn a profit and/or safely operate the Nixon Facility, any of which could adversely affect our business, results of operations and financial condition.

 

Downtime at the Nixon Facility could result in lost margin opportunity, increased maintenance expense, increased inventory, and a reduction in cash available for payment of our obligations.

 

The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations, and we are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Although operating at anticipated levels, the Nixon Facility is still in a recommissioning phase and may require unscheduled downtime for unanticipated reasons, including maintenance and repairs, voluntary regulatory compliance measures, or cessation or suspension by regulatory authorities. Occasionally, the Nixon Facility experiences a temporary shutdown due to power outages because of high winds and thunderstorms. In the case of such a shutdown, the refinery must initiate a standard start-up process, and such process can last several days although we are typically able to resume normal operations the next day. Any scheduled or unscheduled downtime may result in lost margin opportunity, increased maintenance expense and a build-up of refined petroleum products inventory, which could reduce our ability to meet our payment obligations.

 

For the year ended December 31, 2016, the Nixon Facility operated for a total of 291 days, reflecting 75 days of refinery downtime. For the year ended December 31, 2015, the Nixon Facility operated for a total of 341 days, reflecting 24 days of refinery downtime. The significant increase in refinery downtime between the periods was primarily the result of significant under-delivery of crude oil and condensate by GEL, which resulted in 59 of the 75 days of refinery downtime. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate. Further, LEH may, but is not required to, fund our working capital requirements in the event our internally generated cash flows and other sources of liquidity are inadequate.

 

If we are unable to generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. We have relied on LEH to fund working capital requirements when cash reserves and revenue from operations, including sales of refined petroleum products and rental of petroleum storage tanks, were insufficient to fund our working capital requirements. At December 31, 2016 and 2015, accounts payable to LEH was $0.

 

In the event our working capital requirements are inadequate, or we are otherwise unable to secure sufficient liquidity to support our short term and/or long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards, or pursue our business strategies, any of which may have a material adverse effect on our results of operations or liquidity. Our short-term working capital needs are primarily related to acquisition of crude oil and condensate to operate the Nixon Facility, repayment of debt obligations, and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. Our liquidity will affect our ability to satisfy all these needs.

 

We are party to a variety of contracts and agreements with Genesis and GEL, and, if we are unable to successfully maintain this relationship, our operations, liquidity and financial condition may be harmed.

 

We are party to a variety of contracts and agreements with Genesis and GEL for the purchase of crude oil and condensate, transportation of crude oil and condensate, inventory risk management, and other services. Certain of these agreements with Genesis and GEL automatically renew for successive one-year terms until August 2019 unless Genesis and/or GEL provide us with notice of nonrenewal at least 180 days prior to expiration of any renewal term.

 

We are currently involved in a contract-related dispute with GEL. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” for disclosures related to a Joint Marketing Agreement (the “Joint Marketing Agreement”) with GEL, Crude Supply Agreement, and the current contract-related dispute with GEL.)

 

An unfavorable outcome of the contract-related dispute with GEL could have a material adverse effect on us.

 

We are a party to a contract-related dispute with GEL. Litigation and contract-related disputes through arbitration can be expensive, lengthy, disruptive to normal business operations, and divert management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  Moreover, the outcomes of complex legal proceedings or contract-related disputes can be difficult to predict. An unfavorable resolution of a legal proceeding or contract-related dispute could have a material adverse effect on our business, results of operations, financial condition, and reputation. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations.

 

We record provisions for pending litigation when we determine that an unfavorable outcome is likely and the loss can reasonably be estimated. Due to the inherent uncertain nature of litigation, the ultimate outcome or actual cost of settlement may materially differ from estimates. We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet at December 31, 2016.

 

 Our business may suffer if any of the executive officers or other key personnel discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain productivity.

 

Our future success depends on the services of the executive officers and other key personnel and on our continuing ability to recruit, train and retain highly qualified personnel in all areas of our operations. Furthermore, our operations require skilled and experienced personnel with proficiency in multiple tasks. Competition for skilled personnel with industry-specific experience is intense, and the loss of these executives or personnel could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business could be materially adversely affected.

 

Loss of market share by a key customer or consolidation among our customer base that could harm our operating results.

 

For the year ended December 31, 2016, we had 4 customers that accounted for approximately 67% of our refined petroleum product sales. At December 31, 2016 these 4 customers represented approximately $1.6 million in accounts receivable. For the year ended December 31, 2016, LEH, a related party, was 1 of our 4 significant customers. LEH accounted for approximately 27% of our refined petroleum product sales for the year ended December 31, 2016. LEH, which resells jet fuel to a government agency, represented approximately $1.6 million in accounts receivable at December 31, 2016. LEH was not a significant customer during 2015. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (8) Related Party Transactions” for additional disclosures with respect to related parties.)

 

Our customers have a variety of suppliers to choose from and therefore can make substantial demands on us, including demands on product pricing and on contractual terms, which often results in the allocation of risk to us as the supplier. Our ability to maintain strong relationships with our principal customers is essential to our future performance. Our operating results could be harmed if a key customer is lost, reduces their order quantity, requires us to reduce our prices, is acquired by a competitor, or suffers financial hardship.

 

Additionally, our profitability could be adversely affected if there is consolidation among our customer base and our customers command increased leverage in negotiating prices and other terms of sale. We could decide not to sell our refined petroleum products to a certain customer if, because of increased leverage, the customer pressures us to reduce our pricing such that our gross profits are diminished, which could result in a decrease in our revenue. Consolidation may also lead to reduced demand for our products, replacement of our products by the combined entity with those of our competitors, and cancellations of orders, each of which could harm our operating results.

 

The sale of refined petroleum products to the wholesale market is our primary business, and if we fail to maintain and grow the market share of our refined petroleum products, our operating results could suffer.

 

Our success in the wholesale market depends in large part on our ability to maintain and grow our image and reputation as a reliable operator and to expand into and gain market acceptance of our refined petroleum products. Adverse perceptions of product quality, whether justified, or allegations of product quality issues, even if false or unfounded, could tarnish our reputation and cause our wholesale customers to choose refined petroleum products offered by our competitors.

 

We are dependent on third-parties for the transportation of crude oil and condensate into and refined petroleum products out of our Nixon Facility, and if these third-parties become unavailable to us, our ability to process crude oil and condensate and sell refined petroleum products to wholesale markets could be materially and adversely affected.

 

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

 

Our suppliers source a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale and may experience interruptions of supply from that region.

 

Our suppliers source a substantial amount, if not all, of our crude oil and condensate from the Eagle Ford Shale. Consequently, we may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by transportation capacity constraints, curtailment of production, unavailability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in that area.

 

Our refining operations and customers are primarily located within the Eagle Ford Shale and changes in the supply/demand balance in this region could result in lower refining margins.

 

Our primary operating asset, the Nixon Facility, is in the Eagle Ford Shale and we market our refined petroleum products in a single, relatively limited geographic area. Therefore, we are more susceptible to regional economic conditions than our more geographically diversified competitors. Should the supply/demand balance shift in our region due to changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the PADD 3 (Gulf Coast) region to exceed demand, we would have to deliver refined petroleum products to customers outside of our current operating region and thus incur considerably higher transportation costs, resulting in lower refining margins.

 

Hedging of our refined petroleum products and crude oil and condensate may limit our gains and expose us to other risks.

 

We are exposed to commodity price risk related to our crude oil and condensate and refined petroleum product inventories. Crack spreads are a significant driver of our operating margins. Our feedstock acquisition costs and refined petroleum products sales prices depend on numerous factors beyond our control. These factors include domestic and foreign market conditions, political affairs, and economic developments; import supply levels and export opportunities; existing domestic inventory levels; operating and production levels of competing refineries; expansion and/or upgrades of competitors’ facilities; governmental regulations; weather conditions; availability of and access to transportation infrastructure; availability of competing fuels; and seasonal fluctuations. Under our inventory risk management policy, we may use derivative instruments as certain of our refined petroleum product inventories exceed certain thresholds to reduce our commodity price risk. If our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a negative effect on our operations, liquidity and financial condition.

 

Regulation of greenhouse gas emissions could increase our operational costs and reduce demand for our products.

 

Continued political focus on climate change, human activities contributing to the release of large amounts of carbon dioxide and other greenhouse gases into the atmosphere, and potential mitigation through regulation could have a material impact on our operations and financial results. International agreements and federal, state and local regulatory measures to limit greenhouse gas emissions are currently in various stages of discussion and implementation. These and other greenhouse gas emissions-related laws, policies, and regulations may result in substantial capital, compliance, operating, and maintenance costs. The level of expenditure required to comply with these laws and regulations is uncertain and is expected to vary depending on the laws enacted in each jurisdiction, our activities in the particular jurisdiction, and market conditions. The effect of regulation on our financial performance will depend on many factors including, among others, the sectors covered, the greenhouse gas emissions reductions required by law, the extent to which we would be entitled to receive emission allowance allocations, our ability to acquire compliance related equipment, the price and availability of emission allowances and credits, and our ability to recover incurred regulatory compliance costs through the pricing of our products. Material price increases or incentives to conserve or use alternative energy sources could also reduce demand for products we currently sell and adversely affect our sales volumes, revenues and margins.

 

Risks Related to Our Pipelines and Oil and Gas Properties

 

Requests by the BOEM to increase bonds or other sureties to maintain compliance with the BOEM’s regulations could significantly impact our liquidity and financial condition.

 

To cover the various obligations of lessees on the Outer Continental Shelf, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees demonstrate financial strength and reliability per regulations or post bonds or other acceptable assurances that such obligations will be satisfied, unless the BOEM exempts the lessee from such financial assurance requirements. In 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering changing the financial assurance requirements, and it currently plans to publish a revised notice to lessees in 2016.  Part of the Advanced Notice of Proposed Rulemaking includes the BOEM revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit based model. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases.

 

In 2015, we received notice from the BOEM requesting additional supplemental bonds or acceptable financial assurance of approximately $4.2 million for existing pipeline rights-of-way. We are currently working with the BOEM to develop a tailored plan to address the financial assurance requirements. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. At December 31, 2016 and 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM.

 

More stringent requirements imposed by the BOEM and the BSEE related to the decommissioning, plugging, and abandonment of wells, platforms, and pipelines could materially increase our estimate of future AROs.

 

In 2010, the BOEM issued a notice to lessees that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms, and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease. The notice to lessees sets forth more stringent standards for decommissioning timing by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all the well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities which are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment, and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts could cause an increase, perhaps materially, in our future plugging, abandonment, and removal costs, which may translate into a need to increase our estimate of future AROs.

 

Although management has used its best efforts to determine future AROs, assumptions and estimates can be influenced by many factors beyond management’s control. Such factors include, but are not limited to, changes in regulatory requirements, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes, which may cause structural or other damage to pipeline and related assets and oil and gas properties. At December 31, 2016 and 2015, our estimated future asset retirement obligations were approximately $2.0 million. See “Part II, Item 8. Financial Statements and Supplementary Data – Note (11) Asset Retirement Obligations” of this Annual Report for additional information regarding asset retirement obligations.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2.  PROPERTIES

 

LEH manages and operates all our properties pursuant to the Operating Agreement. We believe that our properties are generally adequate for our operations and are maintained in a good state of repair in the ordinary course of business. Following is a summary of our principal facilities and assets:

 

Property		Operating Subsidiary		Description		Business Segment		Owned / Leased		Location
Nixon Facility (56 acres)		Lazarus Energy, LLC Lazarus Refining & Marketing, LLC		Petroleum Processing Petroleum Storage and Terminaling		Refinery Operations		Owned		Nixon, Texas
Freeport Facility (177 acres)		Blue Dolphin Pipe Line Company		Pipeline Operations		Pipeline Transportation		Owned		Freeport, Texas
Pipelines, Oil and Gas Assets		Blue Dolphin Pipe Line Company Blue Dolphin Petroleum Company		Exploration and Production		Pipeline Transportation		Owned/ Leasehold Interests		Gulf of Mexico
Corporate Headquarters		Blue Dolphin Services Co.		Administrative Services		Corporate and Other		Leased		Houston, Texas

 

 

Nixon Facility. The 15,000 bpd Nixon Facility consists of a distillation unit, naphtha stabilizer unit, depropanizer unit, approximately 842,000 bbls of crude oil, condensate, and refined petroleum product storage capacity, as well as related loading and unloading facilities and utilities. The Nixon Facility is currently undergoing construction of an additional 256,000 bbls of petroleum storage capacity. When construction is complete, total crude oil, condensate, and refined petroleum storage capacity at the Nixon Facility will exceed 1,000,000 bbls. The Nixon Facility is pledged as collateral under certain of our long-term debt as discussed in Part II, Item 8 “Financial Statements and Supplementary Data – Note (12) Long-Term Debt” of this Annual Report.

 

Freeport Facility. The Freeport Facility includes pipeline easements and rights-of-way, crude oil and natural gas separation and dehydration facilities, a vapor recovery unit and two onshore pipelines. The two onshore pipelines consist of approximately 4 miles of the 20-inch Blue Dolphin Pipeline and a 16-inch natural gas pipeline that connects the Freeport Facility to the Dow Chemical Plant Complex in Freeport, Texas.

 

Pipelines and Oil and Gas Assets. The following provides a summary of our pipeline and oil and gas assets, all of which are in the Gulf of Mexico:

 

						Natural Gas
						Capacity
Pipeline		Ownership		Miles		(MMcf/d)
Blue Dolphin Pipeline(1)		100%		38		180
GA 350 Pipeline(1)		100%		13		65
Omega Pipeline(2)		100%		18		110

 

(1) Currently inactive.

(2) Currently abandoned in place.

 

 

 

 

 

Management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, we recorded an impairment expense of $968,684 related to our pipeline assets at December 31, 2016. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines. Our oil and gas properties were fully impaired in 2011.

 

Oil and gas properties include a 2.5% working interest and a 2.008% net revenue interest in High Island Block 115, a 0.5% overriding royalty interest in Galveston Area Block 321, and a 2.88% working interest and 2.246% net revenue interest in High Island Block 37. Our oil and gas properties had no production during the years ended December 31, 2016 and 2015, and all leases associated with our oil and gas properties have expired. Accordingly, our oil and gas properties were fully impaired in 2011.

 

Corporate Headquarters. We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. Our office lease is discussed more fully in Part II, Item 8 “Financial Statements and Supplementary Data – Note (15) Leases” of this Annual Report.

 

ITEM 3.  LEGAL PROCEEDINGS

 

Genesis Contract-Related Dispute

 

We are party to a variety of contracts and agreements with Genesis and GEL for the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services.

 

In May 2016, GEL filed, in state district court in Harris County, Texas, a petition and application for a temporary restraining order, temporary injunction, and permanent injunction (the “Petition”) against LE and LEH. The Petition alleges that LE breached the Joint Marketing Agreement, and that LEH tortiously interfered with the Joint Marketing Agreement, concerning an agreement by LEH to supply jet fuel acquired from LE to a government agency. The Petition primarily sought temporary and permanent injunctions related to sales of product from the Nixon Facility to this customer. In June 2016, the court issued a temporary injunction against LE and LEH as requested by GEL. LE believes that GEL’s claims in the Petition are without merit and is defending the matter vigorously.

 

In a matter separate from the above referenced Petition, LE filed a demand for arbitration in June 2016, pursuant to the terms of the Dispute Resolution Agreement between the parties (the “Arbitration”). The Arbitration alleges that GEL breached the Crude Supply Agreement by:

 

 

GEL has made counter claims in the Arbitration with allegations against LE similar to those made in the Petition.  GEL is seeking substantial damages, as well as recovery of attorneys’ fee and costs, totaling approximately $44.0 million in the aggregate, based on allegations of breach of contract, fraudulent transfer and unjust enrichment.  We believe GEL’s counter claims are without merit and are defending them vigorously in the Arbitration.  However, any determination by the arbitrator that we owe significant damages to GEL would have a material adverse effect on our business, liquidity and financial condition and results of operations.  If GEL were awarded significant damages, we may not be able to pay such damages, which would affect our ability to continue as a going concern.

 

A hearing date to discuss and attempt to resolve the Petition and Arbitration was set for February 2017, however, the hearing date was rescheduled to April 2017. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations. Accordingly, we have not recorded an asset or a liability on our consolidated balance sheet at December 31, 2016. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations.

 

Other Legal Matters

 

From time to time we are involved in routine lawsuits, claims, and proceedings incidental to the conduct of our business, including mechanic’s liens and administrative proceedings. Management does not believe that such matters will have a material adverse effect on our financial position, earnings, or cash flows.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not applicable.

 

 

 

 

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

 

PART II

 

 

Market Information

 

Our Common Stock currently trades on the OTCQX U.S. Premier tier of the OTC Markets under the ticker symbol “BDCO." The following table sets forth, for the periods indicated, the high and low bid prices for our Common Stock as reported by the OTC Markets. The quotations reflect inter-dealer prices, without adjustment for retail mark-ups, markdowns or commissions and may not represent actual transactions.

 

Quarter Ended	High	Low
2016
December 31	$3.90	$2.62
September 30	$4.10	$1.69
June 30	$4.30	$4.00
March 31	$5.01	$3.60

2015
December 31	$5.51	$3.77
September 30	$5.35	$3.51
June 30	$7.00	$4.49
March 31	$5.00	$4.00

 

Stockholders

 

At March 31, 2017, we had 273 record holders of our Common Stock. We have approximately 3,000 beneficial holders of our Common Stock.

 

Dividends

 

Under certain of our secured loan agreements, we are restricted from declaring or paying any dividend on our Common Stock without the prior written consent of the lender.

ITEM 6.  SELECTED FINANCIAL DATA

 

Not applicable.

 

 

You should read the following discussion together with the financial statements and the notes thereto included elsewhere in this Annual Report. This discussion contains forward-looking statements that are based on management’s current expectations, estimates, and projections about our business and operations. The cautionary statements made in this Annual Report should be read as applying to all related forward-looking statements wherever they appear in this Annual Report. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements due to many factors, including those we discuss under “Part I, Item 1A. Risk Factors” and elsewhere in this Annual Report. You should read such risk factors and forward-looking statements in this Annual Report.

 

Company Overview

 

See “Part I, Item 1. Business” included in this Annual Report for detailed information related to our business and operations.

 

Major Influences on Results of Operations

 

Our refinery operations business segment represented approximately 99% of total revenue for the years ended December 31, 2016 and 2015. As a margin-based business, our refinery operations are primarily affected by crack spreads, our product slate, and refinery downtime.

 

Crack Spreads

 

The prices of crude oil and refined petroleum products are the most significant driver of margins, and they have historically been subject to wide fluctuations. Our cost to acquire crude oil and condensate and the price for which our refined petroleum products are ultimately sold depend on the economics of supply and demand. Supply and demand are affected by numerous factors, most, if not all, of which are beyond our control, including:

 

 

 

 

 

 

 

 

 

 

 

For the year ended December 31, 2016, our average crack spread was $1.67 per bbl compared to $7.17 per bbl for the year ended December 31, 2015, reflecting a decrease of $5.50 per bbl. Our gross profit between the periods decreased $22,303,396, or 79%, primarily because of lower crack spreads.

Product Slate

 

Management periodically determines whether to change product mix, as well as maintain, increase, or decrease inventory levels based on various factors. These factors include the crude oil pricing market in the U.S. Gulf Coast region, the refined petroleum products market in the same region, the relationship between these two markets, fulfilling contract demands, and other factors that may impact our operations, financial condition, and cash flows.

 

During 2016, we adjusted our product slate. We increased production of military jet fuel and ceased production of Jet A fuel. Military jet fuel and Jet A fuel are produced by separating the distillate stream into kerosene and diesel and blending the kerosene with a portion of the heavy naphtha stream.   Jet A fuel, and to a greater extent military jet fuel, are considered higher value products, significantly upgrading the value of the naphtha component. To offset weaker demand for HOBM in the U.S. local market, we also began selling low-sulfur diesel to customers that export to Mexico. HOBM and low-sulfur diesel are produced from our heavy oil stream.

 

Refinery Downtime

 

The safe and reliable operation of the Nixon Facility is key to our financial performance and results of operations, and we are particularly vulnerable to disruptions in our operations because all our refining operations are conducted at a single facility. Although operating at anticipated levels, the Nixon Facility is still in a recommissioning phase and may require unscheduled downtime for unanticipated reasons, including maintenance and repairs, voluntary regulatory compliance measures, or cessation or suspension by regulatory authorities. Occasionally, the Nixon Facility experiences a temporary shutdown due to power outages from high winds and thunderstorms. In the case of such a shutdown, the refinery must initiate a standard start-up process, and such process can last several days although we are typically able to resume normal operations the next day. Any scheduled or unscheduled downtime may result in lost margin opportunity, increased maintenance expense and a build-up of refined petroleum products inventory, which could reduce our ability to meet our payment obligations.

 

During the year ended December 31, 2016, GEL significantly under-delivered crude oil and condensate to the Nixon Facility. This resulted in significant refinery downtime and significant decreases in refinery throughput and refinery production for 2016. For the year ended December 31, 2016, the Nixon Facility had 75 days of refinery downtime (59 days of which was attributable to GEL) compared to 24 days of refinery downtime for the year ended December 31, 2015. On a calendar day basis, total refinery throughput and total refinery production decreased 1,632 bpd, or approximately 14%, and 1,657 bpd, or approximately 15%, respectively, for the year ended December 31, 2016 compared to the same period in 2015.

 

Although GEL resumed deliveries of crude oil and condensate to the Nixon Facility intermittently from July to December 2016, the adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

Key Relationships

 

Relationship with LEH

 

We are party to a variety of contracts and agreements with LEH, including an Operating Agreement, a Product Sales Agreement, a Terminal Services Agreement, a Loan and Security Agreement, and a Promissory Note. In addition, we currently rely on advances from LEH to fund our working capital requirements. LEH may, but is not required to, fund our working capital requirements. There can be no assurances that LEH will continue to fund our working capital requirements. (See “Part I, Item 8. Financial Statements and Supplementary Data – Note (8) Related Party Transactions” for a summary of the contracts and agreements that we have in place with LEH.)

 

Relationship with Genesis and GEL

 

We are party to a variety of contracts and agreements with Genesis and GEL for the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” for a summary of the contracts and agreements that we have in place with Genesis and GEL.) We currently have a contract-related dispute with GEL related to these agreements. In connection with this dispute, GEL significantly under-delivered crude oil and condensate to the Nixon Facility during 2016. This resulted in significant refinery downtime and a significant decrease in refinery throughput and refined petroleum product sales for the year ended December 31, 2016. Although GEL resumed deliveries of crude oil and condensate to the Nixon Facility intermittently from July to December 2016, the adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. (See “Part I, Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” and for disclosures related to the current contract-related dispute with GEL.)

 

Results of Operations

 

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 and represent approximately 99% of our operations. 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 and represent less than 1% of our operations.

In this Results of Operations section, we review:

 

 

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GLOSSARY OF SELECTED FINANCIAL AND PERFORMANCE MEASURES

Management uses generally accepted accounting principles (“GAAP”) and certain non-GAAP performance measures to assess our results of operations. Certain performance measures used by management to assess our operating results and the effectiveness of our business segments are considered non-GAAP performance measures. These performance measures may differ from similar calculations used by other companies within the petroleum industry, thereby limiting their usefulness as a comparative measure.

For our refinery operations business segment, we refer to certain refinery throughput and production data in the explanation of our period over period changes in results of operations. For our consolidated results, we refer to our consolidated statements of operations in the explanation of our period over period changes in results of operations.

Below are definitions of key financial performance measures used by management:

 

Consolidated Results

Year Ended December 31, 2016 (the “Current Year”) Compared to Year Ended December 31, 2015 (the “Prior Year”).

 

Total Revenue from Operations. For the Current Year we had total revenue from operations of $167,855,316 compared to total revenue from operations of $221,732,620 for the Prior Year. The approximate 24% decrease in total revenue from operations between the periods was primarily the result of lower refinery throughput and lower refined product prices. Lower refinery throughput for the Current Year was due to significant under-delivery of crude oil and condensate by GEL. Most of our revenue in the Current Year came from refined petroleum product sales, which generated revenue of $165,413,778, or more than 99% of total revenue from operations, compared to $220,438,588, or more than 99% of total revenue from operations, in the Prior Year. We recognized $2,366,548 in tank rental revenue in the Current Year compared to $1,147,568 in the Prior Year. The significant increase in tank rental revenue between the Current Year and Prior Year primarily related to the addition of a new tank rental lease agreement.

 

Cost of Refined Products Sold. Cost of refined products sold was $161,714,526 for the Current Year compared to $193,216,959 for the Prior Year. The approximate 16% decrease in cost of refined products sold was the result of lower crude costs per bbl and a decrease in refinery throughput in the Current Year compared to the Prior Year.

 

Gross Profit. For the Current Year gross profit totaled $6,065,801 compared to $28,369,197 for the Prior Year, representing a decrease of $22,303,396. The approximate 79% decrease in gross profit between the periods primarily related to lower crack spreads. Our average crack spread was $1.67 per bbl for the Current Year compared to $7.17 per bbl for the Prior Year, reflecting a decrease of $5.50 per bbl.

 

Refinery Operating Expenses. We recorded refinery operating expenses of $12,040,676 in the Current Year compared to $11,683,658 in the Prior Year, an increase of approximately 3%. Refinery operating expenses per bbl of throughput were $3.35 in the Current Year compared to $2.80 in the Prior Year. The $0.55 increase in refinery operating expenses per bbl of throughput between the periods was primarily the result of lower refinery throughput and an increase in off-site tank leasing expense in the Current Year. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (8) Related Party Transactions” for additional disclosures related to components of refinery operating expenses.)

 

JMA Profit Share. Under the Joint Marketing Agreement, Gross Profits are shared between the parties. If Gross Profits are positive, then the JMA Profit Share will reflect an expense to us. If Gross Profits are negative, then the JMA Profit Share will reflect a credit to us. For the Current Year, the JMA Profit Share was $359,260 compared to $5,820,329 for the Prior Year.  The significant reduction in JMA Profit Share between the periods was the result of the significant decrease in Gross Profits and lower Performance Fees under the Joint Marketing Agreement. Factors that contributed to the decrease in Gross Profits were significantly lower refined product prices and lower sales volume between the periods. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” for further discussion related to the Joint Marketing Agreement, JMA Profit Share, Gross Profits and the contract-related dispute with GEL.)

General and Administrative Expenses. We incurred general and administrative expenses of $2,708,594 in the Current Year compared to $1,525,577 in the Prior Year. The significant increase in general and administrative expenses in the Current Year compared to the Prior Year primarily related to an increase in legal fees associated with the contract-related dispute with GEL.

Depletion, Depreciation and Amortization. We recorded depletion, depreciation and amortization expenses of $1,935,644 in the Current Year compared to $1,647,586 in the Prior Year. The approximate 17% increase in depletion, depreciation and amortization expenses for the Current Year compared to the Prior Year primarily related to additional depreciable refinery assets that were placed in service.

 

Impairment Expense. Impairment expense totaled $968,684 for the Current Year compared to $0 for the Prior Year. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor are being permanently abandoned, and no new third-party wells are being drilled near our pipelines. Consequently, we fully impaired our pipeline assets at December 31, 2016, resulting in the impairment expense of $968,684.

 

Easement, Interest and Other Income. We recorded $1,924,893 in easement, interest and other income for the Current Year compared to $980,266 in the Prior Year. Easement, interest and other income in the Current Year included a write down of $1,377,546 related to accounts payable. Easement, interest and other income in the Prior Year included recognition of a one-time gain of $660,000 related to the Grynberg Matter. Excluding the non-recurring write down of accounts payable in the Current Year and the one-time gain in the Prior Year, easement, interest and other income increased by approximately 71% between the periods.

 

Income Tax Expense. We recognized an income tax expense of $3,607,237 in the Current Year compared to an income tax expense of $2,434,302 in the Prior Year. Income tax expense in the Current Year related to recording a full valuation allowance against deferred tax assets. Income tax expense in the Prior Year primarily related to deferred federal income taxes. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (16) Income Taxes” for additional disclosures related to income taxes.)

 

Net Income (Loss). For the Current Year, we reported a net loss of $15,767,448, or a loss of $1.51 per share, compared to net income of $4,403,239, or income of $0.42 per share, for the Prior Year. The $1.93 per share decrease in net income between the periods was the result of lower refined petroleum product sales, higher refinery operating expenses, and income tax expense.

 

Underlying factors that contributed to the net loss for the Current Year include: (i) decreased margins on refined petroleum products because of lower crack spreads and (ii) GEL significantly under-delivering crude oil and condensate to the Nixon Facility, which resulted in significant refinery downtime and significant decreases in refinery throughput and refined petroleum product sales.

 

Non-GAAP Financial Measures

 

To supplement our consolidated results, management uses certain non-GAAP financial measures. Management believes that Adjusted EBITDA and EBITDA help investors evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. These non-GAAP financial measures are reconciled to GAAP-based results below. These non-GAAP financial measures should not be considered an alternative for GAAP results. The adjustments are provided to enhance an overall understanding of our financial performance for the applicable periods and are indicators management believes are relevant and useful. These performance measures may differ from similar calculations used by other companies within the petroleum industry, thereby limiting their usefulness as a comparative measure. (See “Part II, Item 8. Financial Statements and Supplementary Data” for comparative GAAP results.)

 

 

 

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Adjusted EBITDA and EBITDA, Reconciliation to GAAP.

 

	Years Ended December 31,
	2016				2015
	Segment				Segment
	Refinery	Pipeline	Corporate &		Refinery	Pipeline	Corporate &
	Operations	Transportation	Other	Total	Operations	Transportation	Other	Total
Revenue from operations	$167,780,326	$74,990	$-	$167,855,316	$221,586,156	$146,464	$-	$221,732,620
Less: cost of operations(1)	(175,340,816)	(1,467,021)	(983,112)	(177,790,949)	(205,403,355)	(45,931)	(1,215,929)	(206,665,215)
Other non-interest income(2)	-	1,914,607	-	1,914,607	-	312,500	660,000	972,500
Adjusted EBITDA	(7,560,490)	522,576	(983,112)	(8,021,026)	16,182,801	413,033	(555,929)	16,039,905
Less: JMA Profit Share(3)	(359,260)	-	-	(359,260)	(5,820,329)	-	-	(5,820,329)
EBITDA	$(7,919,750)	$522,576	$(983,112)	$(8,380,286)	$10,362,472	$413,033	$(555,929)	$10,219,576
Depletion, depreciation and
amortization				(1,935,644)				(1,647,586)
Interest expense, net				(1,844,281)				(1,734,449)
Income before income taxes				(12,160,211)				6,837,541
Income tax expense				(3,607,237)				(2,434,302)
Net income				$(15,767,448)				$4,403,239

 

(1)	Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within the Pipeline Transportation Operation cost includes related impairment expense. 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 “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – FLNG Easement Agreements” for further discussion related to FLNG.)
(3)	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” for further discussion of the Joint Marketing Agreement and the contract-related dispute with GEL.)

 

Adjusted EBITDA and EBITDA, Current Year Compared to Prior Year.

 

For the Current Year, refinery operations adjusted EBITDA, total adjusted EBITDA, refinery operations EBITDA, and total EBITDA decreased significantly compared to the Prior Year. The significant decreases were primarily the result of lower margins from refined petroleum products and lower refinery throughput. Margins decreased primarily because of lower crack spreads. Lower refinery throughput for the Current Year was due to significant under-delivery of crude oil and condensate by GEL. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

 

Refinery Operations Adjusted EBITDA. Refinery operations adjusted EBITDA for the Current Year was a loss of $7,560,490 compared to income of $16,182,801 for the Prior Year. This represented a decrease in refinery operations adjusted EBITDA of $23,743,291 for the Current Year compared to the Prior Year.

 

Total Adjusted EBITDA. Total adjusted EBITDA for the Current Year was a loss of $8,021,026 compared to income of $16,039,905 for the Prior Year. This represented a decrease in total adjusted EBITDA of $24,060,931 for the Current Year compared to the Prior Year.

 

Refinery Operations EBITDA. Refinery operations EBITDA for the Current Year was a loss of $7,919,750 compared to income of $10,362,472 for the Prior Year. This represented a decrease in refinery operations EBITDA of $18,282,222 for the Current Year compared to the Prior Year.

 

Total EBITDA. Total EBITDA for the Current Year was a loss of $8,380,286 compared to income of $10,219,576 for the Prior Year. This represented a decrease in total EBITDA of $18,599,862 for the Current Year compared to the Prior Year.

 

Refinery Operating Income (Loss), Reconciliation to GAAP.

 

	2016	2015
Total refined petroleum product sales	$165,413,778	$220,438,588
Less: Cost of refined petroleum products sold	(161,714,526)	(193,216,959)
Less: Refinery operating expenses	(12,040,676)	(11,683,658)
Refinery operating income before JMA Profit Share	(8,341,424)	15,537,971
Less: JMA Profit Share	(359,260)	(5,820,329)
Refinery operating income (loss)	$(8,700,684)	$9,717,642
Total refined petroleum product sales (bbls)	3,638,620	3,955,757

 

Refinery Operating Income (Loss), Current Year Compared to Prior Year.

 

For the Current Year, refinery operating loss totaled $8,700,684 compared to refinery operating income of $9,717,642 for the Prior Year, representing a decrease of $18,418,326. The loss for the Current Year was primarily a result of lower margins from refined petroleum products and lower refinery throughput. Margins on refined petroleum products decreased primarily because of lower crack spreads. Lower refinery throughput for the Current Year was due to significant under-delivery of crude oil and condensate by GEL. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

Refinery Operations Business Segment Results

 

During the Current Year, our average crack spread was $1.67 per bbl compared to $7.17 per bbl for the Prior Year, reflecting a decrease of $5.50 per bbl. Our gross profit between the periods decreased $22,303,396, or 79%, primarily because of lower crack spreads.

 

In addition, GEL significantly under-delivered crude oil and condensate to the Nixon Facility. This resulted in lower refinery throughput and significant refinery downtime in the Current Year compared to the Prior Year. Although GEL resumed deliveries of crude oil and condensate to the Nixon Facility intermittently from July to December 2016, the adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition. In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  We are unable to predict the outcome of the current proceedings with Genesis and GEL or their ultimate impact, if any, on our business, financial condition or results of operations. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

 

 

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Refinery Throughput and Production Data.

 

Following are refinery operational metrics for the Nixon Facility:

 

	2016	2015
Calendar Days	366	365
Refinery downtime	(75)	(24)
Operating Days	291	341
Total refinery throughput (bbls)	3,594,231	4,179,952
Operating days:
bpd	12,351	12,258
Capacity utilization rate	82.3%	81.7%
Calendar days:
bpd	9,820	11,452
Capacity utilization rate	65.5%	76.3%
Total refinery production (bbls)	3,496,011	4,091,203
Operating days:
bpd	12,014	11,998
Capacity utilization rate	80.1%	80.0%
Calendar days:
bpd	9,552	11,209
Capacity utilization rate	63.7%	74.7%

 

Note:

The difference between total refinery throughput (volume processed as input) and total refinery production (volume processed as output) represents refinery fuel use and loss.

 

Current Year Compared to Prior Year.

 

Refinery Downtime. The Nixon Facility operated for a total of 291 days in the Current Year, reflecting 75 days of refinery downtime. Comparatively, the Nixon Facility operated for a total of 341 days in the Prior Year, reflecting 24 days of refinery downtime. The significant increase in refinery downtime between the periods was primarily the result of significant under-delivery of crude oil and condensate by GEL. Refinery downtime in the Current Year attributable to GEL was 59 days. Refinery downtime in the Prior Year related to scheduled and unscheduled maintenance. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Legal Matters” for disclosures related to the current contract-related dispute with GEL.)

 

Total Refinery Throughput. On an operating day basis, total refinery throughput was flat for the Current Year compared to the Prior Year. The Nixon Facility processed 12,351 bpd of crude oil and condensate for the Current Year compared to 12,258 bpd of crude oil and condensate for the Prior Year, an increase of 93 bpd. On a calendar day basis, total refinery throughput decreased approximately 14% for the Current Year compared to the Prior Year. The Nixon Facility processed 9,820 bpd of crude oil and condensate for the Current Year compared to 11,452 bpd of crude oil and condensate for the Prior Year, a decrease of 1,632 bpd. The sharp decrease on a calendar day basis related to significant refinery downtime in the Current Year.

 

Total Refinery Production. On an operating day basis, total refinery production was also flat for the Current Year compared to the Prior Year. The Nixon Facility produced 12,014 bpd of refined petroleum products for the Current Year compared to 11,998 bpd of refined petroleum products for the Prior Year, an increase of 16 bpd. On a calendar day basis, total refinery production decreased approximately 15% for the Current Year compared to the Prior Year. The Nixon Facility produced 9,552 bpd of refined petroleum products for the Current Year compared to 11,209 bpd of refined petroleum products for the Prior Year, a decrease of 1,657 bpd. The sharp decrease on a calendar day basis related to significant refinery downtime in the Current Year.

 

Capacity Utilization Rate. On an operating day basis, the capacity utilization rate for both refinery throughput and refinery production increased less than 1% for the Current Year compared to the Prior Year. The capacity utilization rate for refinery throughput for the Current Year was 82.3% compared to 81.7% for the Prior Year. The capacity utilization rate for refinery production for the Current Year was 80.1% compared to 80.0% for the Prior Year. On barrel a per day basis, capacity utilization rate between the periods increased slightly because of higher total refinery throughput and total refinery production.

 

On a calendar day basis, the capacity utilization rate for both refinery throughput and refinery production decreased approximately 11% for the Current Year compared to the Prior Year. The capacity utilization rate for refinery throughput for the Current Year was 65.5% compared to 76.3% for the Prior Year. The capacity utilization rate for refinery production for the Current Year was 63.7% compared to 74.7% for the Prior Year. On a barrel per day basis, capacity utilization rate between the periods decreased significantly because of lower total refinery throughput and total refinery production.

 

Refined Petroleum Product Sales Summary.

 

(See “Part II, Item 8. Financial Statements and Supplementary Data - Note (14) Concentration of Risk” for a discussion of refined petroleum product sales.)

 

Refined Petroleum Product Economic Hedges.

 

Under our inventory risk management policy, commodity futures contracts are used to mitigate the volatile change in value for certain of our refined petroleum product inventories. For the Current Year, our refinery operations business segment recognized a loss of $2,629,298 on settled transactions and a gain of $183,400 on the change in value of open contracts from December 31, 2015 to December 31, 2016. For the Prior Year, our refinery operations business segment recognized a gain of $4,409,913 on settled transactions and a loss of $679,300 on the change in value of open contracts from December 31, 2014 to December 31, 2015. Although commodity price increases were similar between the periods, larger volumes were hedged in the Current Year compared to the Prior Year.

 

Liquidity and Capital Resources

 

Overview

 

Our primary use of cash flow is to operate the Nixon Facility, purchase crude oil and condensate, and fund capital expenditures. Our primary sources of liquidity have been cash reserves, revenue from operations, LEH, and borrowings under bank facilities. Our liquidity was severely constrained in 2016, principally because of lower crack spreads and lower refinery throughput. As discussed within this “Liquidity and Capital Resources” section, management has determined that there is substantial doubt about our ability to continue as a going concern due to consecutive quarterly net losses, insufficient working capital, litigation risk, crude supply issues, and financial covenant defaults in secured loan agreements. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Operating Risks-Going Concern” for additional discussion related to going concern.)

We are taking aggressive actions to improve operations and liquidity by: (i) continuing with Nixon Facility capital improvements, including upgrading the refinery’s heat exchangers and increasing petroleum storage tank capacity, (ii) increasing military jet fuel sales and low-sulfur diesel exports to Mexico, (iii) restructuring customer contracts as they come up for renewal to incorporate minimum sales volumes, (iv) working to secure a long-term crude oil and condensate supply arrangement, (v) exploring alternative funding sources for crude oil and condensate purchases, and (vi) seeking additional financing to meet ongoing liquidity needs. Management is confident that it is taking the necessary steps to assist the Company in executing its plan. However, there can be no assurance that our plan will be successful or that we will be able to obtain additional financing on commercially reasonable terms or at all.

 

Crude Oil and Condensate Supplies

 

Operation of the Nixon Facility depends on our ability to purchase adequate crude supplies on favorable terms. We are currently involved in a contract-related dispute with GEL related to the Crude Supply Agreement. In connection with this dispute, GEL significantly under-delivered crude oil and condensate to the Nixon Facility during 2016. This resulted in 59 days of refinery downtime and significant decreases in refinery throughput and refined petroleum product sales for the year ended December 31, 2016. The contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved, which management believes will occur in the first half of 2017. We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations.

 

To mitigate the impact of GEL’s disruption of crude Supply to the Nixon Facility, we entered a month-to-month evergreen crude oil supply contract with a major integrated oil and gas company in June 2016, as back-up to the Crude Supply Agreement. We ceased purchases of crude oil and condensate from GEL in November 2016, and we began using an alternate crude oil and condensate supplier.

 

We believe that adequate supplies of crude oil and condensate for the Nixon Facility will continue to be available to us from the alternate supplier. We are working to put a long-term crude supply agreement in place, however, our ability to purchase crude oil and condensate is dependent on our liquidity and access to capital, which have been adversely affected by net losses, working capital deficits, the contract-related dispute with GEL, and financial covenant defaults in secured loan agreements.

 

We are pursuing alternative sources to finance crude oil and condensate acquisition costs, including commodity sale and repurchase programs, inventory financing, debt financing, equity financing, or other means. We may not be successful in consummating suitable financing transactions in the period required or at all, securing financing on terms favorable to us, or obtaining crude oil and condensate at the levels needed to earn a profit and/or safely operate the Nixon Facility, any of which could adversely affect our business, results of operations and financial condition.

 

 

 

 

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Cash Flow

 

Our cash flow from operations for the periods indicated was as follows:

 

	Years Ended December 31,
	2016	2015
Cash flow from operations
Adjusted income (loss) from operations	$(9,257,921)	$9,798,849
Change in assets and current liabilities	5,378,581	(2,745,987)
Total cash flow from operations	(3,879,340)	7,052,862
Cash inflows (outflows)
Proceeds from issuance of debt	7,118,969	38,000,000
Payments on debt	(3,701,616)	(12,881,612)
Change in restricted cash for investing activities	-	-
Capital expenditures	(14,100,897)	(11,370,993)
Change in debt issue costs, net	-	(2,456,352)
Change in restricted cash for financing activities	-	-
Total cash outflows	(10,683,544)	11,291,043
Total change in cash flows	$(14,562,884)	$18,343,905

 

We experienced negative cash flow from operations of $3,879,341 for the Current Year compared to positive cash flow from operations of $7,052,862 for the Prior Year, reflecting a $10,932,203 decrease in cash flow from operations between the periods. The decrease was primarily the result of sustaining net losses for the Current Year compared to net income for the Prior Year. Underlying factors that contributed to the net loss for the Current Year include: (i) lower margins on refined petroleum products primarily related to lower crack spreads, (ii) GEL significantly under-delivering crude oil and condensate to the Nixon Facility as discussed above, and (iii) income tax expense.

 

Working Capital

 

During the Current Year, we obtained working capital from related parties under a loan agreement and promissory notes totaling $7,118,969. We had a working capital deficit of $37,812,263 at December 31, 2016 compared to a working capital deficit of $598,807 at December 31, 2015. The significant increase in working capital deficit between the periods primarily related to reclassification of secured long-term debt (and the related debt issue costs) with Sovereign Bank (“Sovereign”) to the current portion within long-term debt. Excluding long-term debt, we had a working capital deficit of $6,099,927 at December 31, 2016 compared to a working capital deficit of $598,807 at December 31, 2015. The significant increase in working capital deficit between the periods was primarily the result of sustaining net losses in 2016 compared to net income in 2015.

 

As discussed elsewhere within this “Liquidity and Capital Resources” section, the contract-related dispute with GEL has affected our ability to obtain working capital through financings. We expect this to continue until the dispute is resolved, which management believes will occur in the first half of 2017.

To meet ongoing operational needs, we are exploring alternative funding sources, including inventory financing, to improve available working capital. We are also relying on LEH to fund working capital requirements when cash reserves and revenue from operations, including sales of refined petroleum products and rental of petroleum storage tanks, are insufficient to fund our working capital requirements. There can be no assurance that we will be able to obtain additional financing on commercially reasonable terms or at all, or that LEH will continue to fund our working capital requirements when our internally generated cash flows and other sources of liquidity are inadequate.

 

Our short-term working capital needs are primarily related to acquisition of crude oil and condensate to operate the Nixon Facility, repayment of debt obligations, and capital expenditures for maintenance, upgrades, and refurbishment of equipment at the Nixon Facility. Our long-term working capital needs are primarily related to repayment of long-term debt obligations. In addition, we continue to utilize capital to reduce operational, safety and environmental risks. We have taken standard steps to conserve working capital and reduce costs. These steps include renegotiation/bidding of services and support contracts as they come up for renewal, reducing personnel overtime hours, delaying payments to vendors, and/or renegotiating alternative payment terms.

 

Capital Spending

 

Management believes capital and efficiency improvements that began in late 2015 and continued throughout 2016 have positioned us for near-term profitability and long-term sustainability. These capital improvements primarily related to construction of new petroleum storage tanks to add to existing petroleum storage tank capacity. In 2016, we completed construction of four new tanks, and we began construction of several additional new tanks that will be completed in 2017. New petroleum storage tanks at the Nixon Facility support future increased refinery throughput, allow for the purchase of different crude types to maximize product yields and margins, and provide an opportunity to generate additional tank rental revenue by leasing to third-parties. When expansion of the Nixon Facility is complete, total crude oil, condensate, and refined petroleum product storage capacity will exceed 1,000,000 bbls.

 

Capital expenditures at the Nixon Facility are being funded by Sovereign long-term debt that was secured in 2015. Available funds under these loans are reflected in restricted cash (current and non-current portions) on our consolidated balance sheets. Restricted cash (current portion) represents funds to pay outstanding construction invoices and to fund construction contingencies. Restricted cash (current portion) totaled $3,347,835 and $3,175,299 at December 31, 2016 and 2015, respectively. Restricted cash, non-current represents funds held in our disbursement account with Sovereign to complete construction of new petroleum storage tanks. Restricted cash, noncurrent totaled $1,582,305 and $15,616,478 at December 31, 2016 and 2015, respectively.

 

Capital expenditures as of the dates indicated were as follows:

 

	Years Ended December 31,
	2016	2015
Cash disbursements	$14,100,897	$11,370,993
Accounts payable(1)	2,286,082	873,665
	$16,386,979	$12,244,658

 

 

We estimate capital spending in 2017 to approximate $3.3 million. Capital expenditures, which will be funded by remaining amounts available under bank facilities secured in 2015 with Sovereign, will primarily be for completion of petroleum storage tanks at the Nixon Facility.

 

See “Part II, Item 8. Financial Statements and Supplementary Data – Note (10) Long-Term Debt, Net” for additional disclosures related to borrowings for capital spending.

 

Contractual Obligations

 

Related Party. We are a party to agreements with Ingleside Crude, LLC (“Ingleside”), Lazarus Marine Terminal I, LLC (“LMT”), LEH, and Jonathan Carroll. Ingleside is a related party of LEH and Jonathan Carroll. LMT is a related party of LEH and Jonathan Carroll. 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. We believe these related party transactions were consummated on terms equivalent to those that prevail in arm’s-length transactions.

 

Genesis. We are party to a variety of contracts and agreements with Genesis and its affiliates for the purchase of crude oil and condensate, transportation of crude oil and condensate, and other services. Certain of these agreements with Genesis and GEL have successive one-year renewals until August 2019 unless sooner terminated by Genesis or GEL with 180 days’ prior written notice.  We are currently involved in a dispute with GEL over certain contractual matters. The adverse change in our relationship with Genesis and GEL has had a material adverse effect on our operations, liquidity, and financial condition.  In addition, the contract-related dispute has affected our ability to obtain financings, prevented us from taking advantage of business opportunities, disrupted normal business operations, and diverted management’s focus away from operations. We expect these effects to continue until the dispute is resolved.  We are unable to predict the outcome of the current proceedings with GEL or their ultimate impact, if any, on our business, financial condition or results of operations. However, an unfavorable resolution of the dispute could have a material adverse effect on our business, liquidity and financial condition and results of operations. (See “Part I, Item 1A. Risk Factors” as well as “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Genesis Agreements” and “Legal Matters” for a summary of the Joint Marketing Agreement and Crude Supply Agreement and disclosures related to the current contract-related dispute with Genesis.)

 

 

Supplemental Pipeline Bonds. In October 2016, we received a letter from the Bureau of Ocean Energy Management (the “BOEM”) summarizing the amount required as additional security on our existing pipeline rights-of-way. The letter, which is a courtesy and does not constitute a formal order by the BOEM, requested that we provide additional supplemental bonds or acceptable financial assurance of approximately $4.6 million. At December 31, 2016 and 2015, we maintained approximately $0.9 million in credit and cash-backed rights-of-way bonds issued to the BOEM. Of the 5 rights-of-way reflected in the BOEM’s October 2016 letter, one right-of-way was abandoned-in-place in 1997. We requested permits from the Bureau of Safety and Environmental Enforcement (the “BSEE”) to decommission and abandon-in-place 3 of the rights-of-way in April 2016, one of which also requires approval from the U.S. Army Corps of Engineers. There can be no assurance that the BOEM will accept a reduced amount of supplemental financial assurance or not require additional supplemental pipeline bonds related to our existing pipeline rights-of-way. If we are required by the BOEM to provide significant additional supplemental bonds or acceptable financial assurance, we may experience a significant and material adverse effect on our operations, liquidity, and financial condition. (See “Part II, Item 8. Financial Statements and Supplementary Data – Note (20) Commitments and Contingencies – Supplemental Pipeline Bonds” for a discussion of supplemental pipeline bonding requirements.)

 

Indebtedness

 

The principal balances outstanding on our long-term debt, net (including related party) for the periods indicated were as follow:

	December 31,
	2016	2015
First Term Loan Due 2034	$23,924,607	$24,643,081
Second Term Loan Due 2034	9,729,853	10,000,000
LEH Loan Agreement	4,000,000	-
Ingleside Note	722,278	-
Notre Dame Debt	1,300,000	1,300,000
Carroll Note	592,412	-
Term Loan Due 2017	184,994	924,969
Capital Leases	135,879	304,618
	40,590,023	37,172,668
Less: Long-term debt less unamortized	(32,212,336)	(1,934,932)
debt issue costs and long-term debt,
related party, current portion
Less: Unamoritized debt issue costs	(2,262,997)	(2,391,482)
	$6,114,690	$32,846,254

 

Additions to long-term debt in the Current Year totaled $7,118,969 and related to a loan agreement with LEH and promissory notes with LEH, Ingleside and Jonathan Carroll. Payments on long-term debt totaled $3,701,616 for the Current Year compared to $12,881,612 in the Prior Year. The Current Year amount reflects payment of $1,797,172 on the promissory note with LEH Note and $7,107 on the promissory note with Ingleside. The Prior Year amount reflects payment of $8,545,466 on a loan to American First National Bank.

 

At December 31, 2016, LE and LRM were in violation of certain financial covenants related to the First Term Loan Due 2034, Second Term Loan Due 2034, and Term Loan Due 2017. Covenant defaults under the secured loan agreements would permit Sovereign to 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 year ended December 31, 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 “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Operating Risks-Going Concern, Note (10) Long-Term Debt, Net, and Note (21) Subsequent Events” for additional disclosures related to long-term debt financial covenant violations.

 

See “Contractual Obligations – Related Party” within the Liquidity and Capital Resources section for additional disclosures with respect to related party indebtedness.

 

Off-Balance Sheet Arrangements

 

None.

 

Critical Accounting Policies

 

Long-Lived Assets

Refinery and Facilities. Additions to refinery and facilities assets are capitalized. Expenditures for repairs and maintenance are included as operating expenses under the Operating Agreement and covered by LEH. 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 the years ended December 31, 2016 and 2015.

Pipelines and Facilities Assets. 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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) guidance on accounting for the impairment or disposal of long-lived assets, we evaluate our pipeline and facilities assets for impairment on a periodic basis, usually annually, and when events or circumstances indicate that the carrying value of these assets may not be recoverable.

Management performed periodic impairment testing of our pipeline and facilities assets in the fourth quarter of 2016. Upon completion of that testing, we recorded an impairment expense of $968,684 related to our pipeline assets at December 31, 2016. All pipeline transportation services to third-parties have ceased, existing third-party wells along our pipeline corridor have been permanently abandoned, and no new third-party wells are being drilled near our pipelines. However, management believes our pipeline assets have future value based on large-scale, third-party production facility expansion projects near the pipelines. 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.

 

Revenue Recognition

Regarding our finished products, low-sulfur diesel is sold to customers that export to Mexico and jet fuel is sold in nearby markets to wholesalers. Our intermediate products, including LPG, naphtha, HOBM, and AGO, are primarily sold to wholesalers and refiners for further blending and processing. Revenue from refined petroleum product 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 fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. Land easement revenue is recognized monthly as earned and included in other income.

 

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.

 

Asset Retirement Obligations

 

FASB ASC guidance related to 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 facility 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 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.

 

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 some portion or all the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any 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, 2016. 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 full valuation allowance against the deferred tax assets as of December 31, 2016.FASB ASC guidance related to income taxes 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 “Part II, Item 8. Financial Statements and Supplementary Data - Note (16) Income Taxes” for further information related to income taxes.)

 

Recently Adopted Accounting Guidance

 

The Financial Accounting Standards Board (“FASB”) issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB Accounting Standards Codification, including changes to non-authoritative SEC content. For the year ended December 31, 2016, we adopted the following recently issued ASU’s:

 

ASU 2016-18, Statement of Cash Flows (Topic 230: Restricted Cash (a Consensus of the FASB Emerging Issues Task Force. In November 2016, FASB issued ASU 2016-18, which will require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. We adopted this accounting pronouncement effective December 31, 2016. Accordingly, our consolidated statement of cash flows for the year ended December 31, 2015 was changed to combine restricted cash with cash and cash equivalents.

 

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 at December 31, 2015 was changed to reclassify approximately $3.5 million previously reported as deferred tax assets, current portion, net to deferred tax assets, net.

 

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 at December 31, 2015 was 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 material impact on our consolidated financial position, results of operations, or cash flows.

 

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 after 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. We adopted this accounting pronouncement effective December 31, 2016. Our assessment of our ability to continue as a going concern is further discussed in “Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” and “Part II, Item 8. Financial Statements and Supplementary Data – Note (1) Organization – Operating Risk-Going Concern” in this Annual Report. The adoption of ASU 2016-18 affected our disclosure requirements.

 

 

 

 

 

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

Crude oil refining is primarily a margin-based business where both crude oil and refined petroleum products are commodities with prices that are highly volatile. Although the Nixon Facility’s product slate and refinery downtime affect our results of operations, crack spread (differential between the cost of our feedstocks and the sales price of our refined petroleum products) is the most significant driver.

 

Under our inventory risk management policy, we may use derivative instruments as certain of our refined petroleum product inventories exceed certain thresholds to reduce our commodity price risk. If our inventory risk management system fails and/or is implemented poorly or not at all, we could experience a negative effect on our operations, liquidity and financial condition.

 

At December 31, 2016, we performed a sensitivity analysis to determine the impact of an increase in the market price of commodity contracts for our economic hedges. Based on this sensitivity analysis, we determined that an increase of $1.00 per barrel in commodity contracts held at December 31, 2016 would have no effect as we held no open commodity instruments at December 31, 2016.

 

Interest Rate Risk

 

We are exposed to interest rate volatility regarding existing variable rate debt that is tied to movements in the U.S. Prime Rate. At December 31, 2016, we had $33,839,454 of variable interest debt with a weighted average interest rate at year end of approximately 6.25%. At December 31, 2016, we performed a sensitivity analysis to determine the impact of an increase in interest rates. Based on this sensitivity analysis, we determined that an increase of 1% in our average floating interest rates at December 31, 2016 would increase interest expense by approximately $338,395 per year.

 

 

 

 

 

 

 

 

 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

Index to Financial Statements

 

Report of Independent Registered Public Accounting Firm	52
Consolidated Balance Sheets	53
Consolidated Statements of Operations	54
Consolidated Statements of Stockholders’ Equity	55
Consolidated Statements of Cash Flows	56
Notes to Consolidated Financial Statements	57

 

 

 

 

 

 

 

 

 

 

Remainder of Page Intentionally Left Blank

 

 

Report of Independent Registered Public Accounting Firm

 

 

The Board of Directors and

Stockholders of Blue Dolphin Energy Company

 

We have audited the accompanying consolidated balance sheets of Blue Dolphin Energy Company and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These concolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Blue Dolphin Energy Company and Subsidiaries as of December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note (1) to the consolidated financial statements, the Company has suffered operating losses and negative cash flows from operations, has a working capital deficiency and is in violation of certain financial covenants in their secured loan agreements. These issues raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note (1) to the consolidated financial statements. The accompanying financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern.

 

 

/s/ UHY LLP                   

UHY LLP

Sterling Heights, Michigan

March 31, 2017

 

Consolidated Balance Sheets

 

	December 31,	December 31,
	2016	2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$1,152,628	$1,853,875
Restricted cash	3,347,835	3,175,299
Accounts receivable, net	2,022,166	5,457,245
Accounts receivable, related party	1,161,589	-
Prepaid expenses and other current assets	1,046,191	939,690
Deposits	138,957	395,414
Inventory	2,075,538	7,808,318
Total current assets	10,944,904	19,629,841
Total property and equipment, net	62,324,463	48,841,812
Restricted cash, noncurrent	1,582,305	15,616,478
Surety bonds	205,000	1,022,000
Trade name	303,346	303,346
Deferred tax assets, net	-	3,607,237
Total long-term assets	64,415,114	69,390,873
TOTAL ASSETS	$75,360,018	$89,020,714
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$14,552,383	$14,882,714
Accounts payable, related party	369,600	300,000
Asset retirement obligations, current portion	17,510	38,644
Accrued expenses and other current liabilities	1,281,582	2,990,891
Interest payable, current portion	323,756	81,467
Long-term debt less unamortized debt issue costs, current portion	31,712,336	1,934,932
Long-term debt, related party, current portion	500,000	-
Total current liabilities	48,757,167	20,228,648
Long-term liabilities:
Asset retirement obligations, net of current portion	2,010,129	1,947,220
Deferred revenues and expenses	83,390	125,085
Long-term debt less unamortized debt issue costs, net of current portion	1,300,000	32,846,254
Long-term debt, related party, net of current portion	4,814,690	-
Long-term interest payable, net of current portion	1,691,383	1,482,801
Total long-term liabilities	9,899,592	36,401,360
TOTAL LIABILITIES	58,656,759	56,630,008
Commitments and contingencies (Note 19)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized; 10,624,714 and
10,603,802 shares issued at December 31, 2016 and December 31, 2015, respectively)	106,248	106,038
Additional paid-in capital	36,818,528	36,738,737
Accumulated deficit	(19,421,517)	(3,654,069)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	16,703,259	32,390,706
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$75,360,018	$89,020,714