BLUE DOLPHIN ENERGY CO
10-Ks and 10-Qs
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
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☑
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2016
or
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☐
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For the
transition period from
to
Commission File No. 0-15905
BLUE DOLPHIN ENERGY COMPANY
(Exact
name of registrant as specified in its charter)
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Delaware
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73-1268729
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State
or other jurisdiction of incorporation or organization
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(I.R.S.
Employer Identification No.)
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801 Travis Street, Suite 2100
Houston, Texas
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77002
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(Address
of principal executive offices)
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(Zip
Code)
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(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
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(Title
of class)
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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.
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Number
of shares of common stock, par value $0.01 per share outstanding at
March 31, 2017: 10,474,714
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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:
Atmospheric gas oil (“AGO”)
. The heaviest
product boiled by a crude distillation unit operating at
atmospheric pressure. This fraction ordinarily sells as distillate
fuel oil, either in pure form or blended with cracked stocks.
Blended AGO usually serves as the premium quality component used to
lift lesser streams to the standards of saleable furnace oil or
diesel engine fuel. Certain ethylene plants, called heavy oil
crackers, can take AGO as feedstock.
Barrel (“bbl”)
. One stock tank bbl, or 42 U.S.
gallons of liquid volume, used about oil or other liquid
hydrocarbons.
Blending
. The physical mixture of several different liquid
hydrocarbons to produce a finished product with certain desired
characteristics. Products can be blended in-line through a manifold
system, or batch blended in tanks and vessels. In-line blending of
gasoline, distillates, jet fuel and kerosene is accomplished by
injecting proportionate amounts of each component into the main
stream where turbulence promotes thorough mixing. Additives,
including octane enhancers, metal deactivators, anti-oxidants,
anti-knock agents, gum and rust inhibitors, and detergents, are
added during and/or after blending to result in specifically
desired properties not inherent in hydrocarbons.
Barrels per Day (“bpd”)
. A measure of the bbls
of daily output produced in a refinery or transported through a
pipeline.
Complexity
. A numerical score that denotes, for a given
refinery, the extent, capability, and capital intensity of the
refining processes downstream of the crude oil distillation unit.
The higher a refinery’s complexity, the greater the
refinery’s capital investment and number of operating units
used to separate feedstock into fractions, improve their quality,
and increase the production of higher-valued products. Refinery
complexities range from the relatively simple crude oil
distillation unit (“topping unit”), which has a
complexity of 1.0, to the more complex deep conversion
(“coking”) refineries, which have a complexity of
12.0.
Condensate
. Liquid hydrocarbons that are produced in
conjunction with natural gas. Condensate is chemically more complex
than LPG. Although condensate is sometimes like crude oil, it is
usually lighter.
Crack Spread
. The differential between the price of crude
oil and the price of the petroleum products extracted from
it.
Crude oil
. A mixture of thousands of chemicals and
compounds, primarily hydrocarbons. Crude oil quality is measured in
terms of density (light to heavy) and sulfur content (sweet to
sour). Crude oil must be broken down into its various components by
distillation before these chemicals and compounds can be used as
fuels or converted to more valuable products.
Depropanizer unit
. A distillation column that is used to
isolate propane from a mixture containing butane and other heavy
components.
Distillates
. The result of crude distillation and therefore
any refined oil product. Distillate is more commonly used as an
abbreviated form of middle distillate. There are mainly four (4)
types of distillates: (i) very light oils or light distillates
(such as our LPG mix and naphtha), (ii) light oils or middle
distillates (such as our jet fuel), (iii) medium oils, and (iv)
heavy oils (such as our low-sulfur diesel and heavy oil-based mud
blendstock (“HOBM”), reduced crude, and
AGO).
Distillation
. The first step in the refining process whereby
crude oil and condensate is heated at atmospheric pressure in the
base of a distillation tower. As the temperature increases, the
various compounds vaporize in succession at their various boiling
points and then rise to prescribed levels within the tower per
their densities, from lightest to heaviest. They then condense in
distillation trays and are drawn off individually for further
refining. Distillation is also used at other points in the refining
process to remove impurities. Lighter products produced in this
process can be further refined in a catalytic cracking unit or
reforming unit. Heavier products, which cannot be vaporized and
separated in this process, can be further distilled in a vacuum
distillation unit or coker.
Distillation tower
. A tall column-like vessel in which crude
oil and condensate is heated and its vaporized components distilled
by means of distillation trays.
Feedstocks
. Crude oil and other hydrocarbons, such as
condensate and/or intermediate products, that are used as basic
input materials in a refining process. Feedstocks are transformed
into one or more finished products.
Finished petroleum products
. Materials or products which
have received the final increments of value through processing
operations, and which are being held in inventory for delivery,
sale, or use.
Intermediate petroleum products
. A petroleum product that
might require further processing before it is saleable to the
ultimate consumer. This further processing might be done by the
producer or by another processor. Thus, an intermediate petroleum
product might be a final product for one company and an input for
another company that will process it further.
Jet fuel
. A high-quality kerosene product primarily used in
aviation. Kerosene-type jet fuel (including Jet A and Jet A-1) has
a carbon number distribution between about 8 and 16 carbon atoms
per molecule; wide-cut or naphtha-type jet fuel (including Jet B)
has between about 5 and 15 carbon atoms per molecule.
Kerosene
. A middle distillate fraction of crude oil
that is produced at higher temperatures than naphtha and lower
temperatures than gas oil. It is usually used as jet turbine fuel
and sometimes for domestic cooking, heating, and
lighting.
Leasehold interest
. The interest of a lessee under an oil
and gas lease.
Light crude
. A liquid petroleum that has a low density and
flows freely at room temperature. It has a low viscosity, low
specific gravity, and a high American Petroleum Institute gravity
due to the presence of a high proportion of light hydrocarbon
fractions.
Liquefied petroleum gas
(“LPG”)
. Manufactured during the
refining of crude oil and condensate; burns relatively cleanly with
no soot and very few sulfur emissions.
MMcf
.
One
million cubic feet; a measurement of gas volume only.
Naphtha
. A refined or partly refined light distillate
fraction of crude oil. Blended further or mixed with other
materials it can make high-grade motor gasoline or jet fuel. It is
also a generic term applied to the lightest and most volatile
petroleum fractions.
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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Petroleum
. A naturally occurring flammable liquid consisting
of a complex mixture of hydrocarbons of various molecular weights
and other liquid organic compounds. The name petroleum covers both
the naturally occurring unprocessed crude oils and petroleum
products that are made up of refined crude oil.
Product Slate
. Represents the type and quality of products
produced.
Propane
. A by-product of natural gas processing and
petroleum refining. Propane is one of a group of LPGs. The others
include butane, propylene, butadiene, butylene, isobutylene and
mixtures thereof. (See also definition of LPG.)
Refined petroleum products
. Refined petroleum products are
derived from crude oil and condensate that have been processed
through various refining methods. The resulting products include
gasoline, home heating oil, jet fuel, diesel, lubricants and the
raw materials for fertilizer, chemicals, and
pharmaceuticals.
Refinery
. Within the oil and gas industry, a refinery is an
industrial processing plant where crude oil and condensate is
separated and transformed into petroleum products.
Sour crude
. Crude oil containing sulfur content of more than
0.5%.
Stabilizer unit
. A distillation column intended to remove
the lighter boiling compounds, such as butane or propane, from a
product.
Sweet crude
. Crude oil containing sulfur content of less
than 0.5%.
Sulfur
. Present at various levels of concentration in many
hydrocarbon deposits, such as petroleum, coal, or natural gas.
Also, produced as a by-product of removing sulfur-containing
contaminants from natural gas and petroleum. Some of the most
commonly used hydrocarbon deposits are categorized per their sulfur
content, with lower sulfur fuels usually selling at a higher,
premium price and higher sulfur fuels selling at a lower, or
discounted, price.
Topping unit
. A type of petroleum refinery that engages in
only the first step of the refining process -- crude distillation.
A topping unit uses atmospheric distillation to separate crude oil
and condensate into constituent petroleum products. A topping unit
has a refinery complexity range of 1.0 to 2.0.
Throughput
. The volume processed through a unit or a
refinery or transported through a pipeline.
Turnaround
. Scheduled large-scale maintenance activity
wherein an entire process unit is taken offline for a week or more
for comprehensive revamp and renewal.
Yield
. The percentage of refined petroleum products that is
produced from crude oil and other feedstocks.
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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TABLE OF CONTENTS
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PART I
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6
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ITEM 1.
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BUSINESS
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6
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ITEM 1A.
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RISK FACTORS
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18
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ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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28
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ITEM 2.
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PROPERTIES
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29
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ITEM 3.
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LEGAL PROCEEDINGS
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30
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ITEM 4.
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MINE SAFETY DISCLOSURES
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31
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PART II
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32
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ITEM 5.
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MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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32
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ITEM 6.
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SELECTED FINANCIAL DATA
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32
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ITEM 7.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
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33
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ITEM 7A.
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
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50
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ITEM 8.
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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51
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Report of Independent Registered Public Accounting
Firm
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Consolidated Balance Sheets
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52
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Consolidated Statements of Operations
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53
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Consolidated Statements of Stockholders’ Equity
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54
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Consolidated Statements of Cash Flows
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55
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Notes to Consolidated Financial Statements
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56
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ITEM 9.
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
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57
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ITEM 9A.
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CONTROLS AND PROCEDURES
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89
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ITEM 9B.
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OTHER INFORMATION
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90
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PART III
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91
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ITEM 10.
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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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91
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ITEM 11.
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EXECUTIVE COMPENSATION
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95
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ITEM 12.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
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97
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ITEM 13.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
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98
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ITEM 14.
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PRINCIPAL ACCOUNTING FEES AND SERVICES
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101
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PART IV
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ITEM 15.
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EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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102
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ITEM 16.
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FORM 10-K SUMMARY
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102
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SIGNATURES
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108
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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:
●
Lazarus Energy,
LLC, a Delaware limited liability company
(“LE”).
●
Lazarus Refining
& Marketing, LLC, a Delaware limited liability company
(“LRM”).
●
Blue Dolphin Pipe
Line Company, a Delaware corporation.
●
Blue Dolphin
Petroleum Company, a Delaware corporation.
●
Blue Dolphin
Services Co., a Texas corporation.
(See
"Part I, Item 2. Properties” of this Annual Report for
additional information regarding our operating
subsidiaries.)
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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:
●
Net Losses –
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. The $1.93 per share decrease in net income
between the periods was the result of lower margins on refined
petroleum products, lower refinery throughput and significant
refinery downtime, higher refinery operating expenses, and income
tax expense for the year ended December 31, 2016. Margins on
refined petroleum products decreased primarily because of lower
crack spreads.
●
Working Capital
Deficits – 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 described above.
●
Adverse Change in
Relationship with Genesis Energy, LLP (“Genesis”) and
GEL Tex Marketing, LLC (“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. We currently have a
contract-related dispute with GEL related to certain of these
agreements. 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 our
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.
●
Crude Supply Issues
– Historically, we purchased light crude oil and condensate
for the Nixon Facility from GEL pursuant to a Crude Oil Supply and
Throughput Services Agreement (the “Crude Supply
Agreement”). As noted above, 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. 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. 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 the contract-related dispute with GEL and other factors, as
noted above.
●
Financial Covenant
Defaults – At December 31, 2016, we were in violation of
certain financial covenants in secured loan agreements with
Sovereign. Covenant defaults under the secured 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 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.
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BLUE
DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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:
●
Part I, Item 1A.
Risk Factors
●
Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations:
–
Key Relationships
– Relationship with Genesis and GEL
–
Results of
Operations – Non-GAAP Financial Measures
●
Part II, Item 8.
Financial Statements and Supplementary Data:
–
Note (9) Long-Term
Debt, Net
–
Note(20)
Commitments and Contingencies – Genesis Agreements and Legal
Matters
–
Note (21)
Subsequent Events
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.
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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.
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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. J
et 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.
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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
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Accounts payable
(1)
|
2,286,082
|
873,665
|
|
|
$
16,386,979
|
$
12,244,658
|
(1) Represents construction-related vendor
invoices awaiting payment from the loan disbursement
account.
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.
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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.
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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”).
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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.
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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
o
il 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.
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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.
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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 s
tate
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:
●
Personnel serving
in capacities equivalent to the capacities of corporate executive
officers, including Chief Executive Officer and Chief Financial
Officer, as well as general manager and environmental, health and
safety personnel; and
●
Personnel providing
administrative and professional services, including accounting,
human resources, insurance, and regulatory compliance.
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.
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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.
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.)
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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.
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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.
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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).
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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.
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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:
●
changes in
foreign, domestic, and local economic conditions;
●
foreign and
domestic demand for fuel products;
●
worldwide
political conditions, particularly in significant oil producing
regions;
●
foreign and
domestic production levels of crude oil, other feedstocks, and
refined petroleum products and the volume of crude oil, feedstocks,
and refined petroleum products imported into the U.S.;
●
availability of
and access to transportation infrastructure;
●
capacity
utilization rates of refineries in the U.S.;
●
Organization of
Petroleum Exporting Countries’ influence on oil
prices;
●
development and
marketing of alternative and competing fuels;
●
commodities
speculation;
●
natural disasters
(such as hurricanes and tornadoes), accidents, interruptions in
transportation, inclement weather or other events that can cause
unscheduled shutdowns or otherwise adversely affect our
refineries;
●
federal and state
governmental regulations and taxes; and
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●
local
factors, including market conditions, weather conditions and the
level of operations of other refineries and pipelines in our
markets.
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.)
24
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DOLPHIN ENERGY COMPANY
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2016
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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.
25
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DOLPHIN ENERGY COMPANY
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|
2016
FORM 10-K
|
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.
26
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BLUE
DOLPHIN ENERGY COMPANY
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|
2016
FORM 10-K
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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.
27
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2016
FORM 10-K
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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.
None.
28
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DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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.
●
Blue Dolphin
Pipeline – The Blue Dolphin Pipeline consists of 16-inch and
20-inch offshore pipeline segments, including a trunk line and
lateral lines, that run from an offshore anchor platform in
Galveston Area Block 288 to our Freeport Facility;
●
GA 350 Pipeline
– The GA 350 Pipeline is an 8-inch offshore pipeline
extending from Galveston Area Block 350 to a subsea interconnect
and tie-in with a transmission pipeline in Galveston Area Block
391; and
29
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2016
FORM 10-K
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●
Omega Pipeline
– The Omega Pipeline is a 12-inch offshore pipeline that
originates in the High Island Area, East Addition Block A-173 and
extends to West Cameron Block 342, where it was previously
connected to the High Island Offshore System.
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.
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:
(i)
overcharging for
crude oil and condensate based on Genesis’ cost as defined in
the Crude Supply Agreement,
(ii)
overcharging for
trucking costs, and
(iii)
significantly
under-delivering crude oil and condensate, resulting in 59 days of
refinery downtime and significant decreases in refinery throughput,
refinery production, and refined petroleum product sales for the
year ended December 31, 2016.
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.
30
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2016
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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.
Not
applicable.
Remainder
of Page Intentionally Left Blank
31
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DOLPHIN ENERGY COMPANY
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2016
FORM 10-K
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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.
Not
applicable.
32
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
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:
●
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 (e.g., mandated renewable fuels standards, proposed
climate change laws and regulations, and increased mileage
standards for vehicles);
●
Weather
conditions;
●
Availability of and
access to transportation infrastructure;
●
Availability of
competing fuels (e.g., renewables); and
●
Seasonal
fluctuations.
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.
33
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.)
34
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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:
●
Definitions
of key financial performance measures used by
management;
●
Consolidated
results, which reflect financial results for our Refinery
Operations and Pipeline Transportation business
segments;
●
Non-GAAP
financial results; and
●
Refinery
Operations business segment results.
Remainder of Page Intentionally Left Blank
35
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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:
Adjusted Earnings Before Interest, Income Taxes and Depreciation
(“EBITDA”)
.
Reflects EBITDA excluding the JMA Profit
Share.
Refinery
Operations Adjusted EBITDA
.
Reflects adjusted EBITDA for our refinery operations business
segment.
Total
Adjusted EBITDA
.
Reflects adjusted EBITDA for our refinery
operations and pipeline transportation business segments, as well
as corporate and other.
Capacity Utilization Rate
. A percentage measure that
indicates the amount of available capacity that is being used in a
refinery or transported through a pipeline. With respect to the
Nixon Facility, the rate is calculated by dividing total refinery
throughput or total refinery production on a bpd basis by the total
capacity of the Nixon Facility (currently 15,000 bpd).
Cost of Refined Products Sold
.
Primarily includes purchased crude oil and
condensate costs, as well as transportation, freight and storage
costs.
Depletion, Depreciation and Amortization
. Represents property and equipment, as well as
intangible assets that are depreciated or amortized based on the
straight-line method over the estimated useful life of the related
asset.
Downtime
. Scheduled and/or unscheduled periods in which the
Nixon Facility is not operating. Downtime may occur for a variety
of reasons, including bad weather, power failures, preventive
maintenance, equipment inspection, equipment repair due to
mechanical failure, voluntary regulatory compliance measures,
cessation or suspension by regulatory authorities, and inventory
management.
Easement, Interest and Other Income
.
Reflects income related to an easement agreement
with FLNG Land II, Inc., a Delaware corporation
(“FLNG”), which was recorded as land easement revenue
and recognized monthly as earned. See “Part II, Item 8.
Financial Statements and Supplementary Data – Note (20)
Commitments and Contingencies – FLNG Easement
Agreements” for additional discussion of easement
income.
EBITDA
.
Reflects earnings before: (i) interest income
(expense), (ii) income taxes, and (iii) depreciation and
amortization.
Refinery
Operations EBITDA
. Reflects
EBITDA for our refinery operations business
segment.
Total
EBITDA
. Reflects EBITDA for our
refinery operations and pipeline transportation business segments,
as well as corporate and other.
General and Administrative Expenses
.
Primarily include corporate costs, such as
accounting and legal fees, office lease expenses, and
administrative expenses.
Income Tax Expense
.
Includes federal and state taxes, as well as
deferred taxes, arising from temporary differences between income
for financial reporting and income tax
purposes.
JMA Profit Share
.
Represents the
GEL
Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement; is an indirect
operating expense.
Net Income
. Represents total
revenue from operations less total cost of operations, total other
expense, and income tax expense.
Operating Days
. Represents the number of days in a period in
which the Nixon Facility operated. Operating days is calculated by
subtracting downtime in a period from calendar days in the same
period.
Refinery Operating Expenses
.
Reflect the direct operating expenses of the Nixon
Facility, including direct costs of labor, maintenance materials
and services, chemicals and catalysts and utilities. Includes fees
paid to LEH to manage and operate the Nixon Facility pursuant to
the Operating Agreement.
Refinery Operating Income
.
Reflects refined petroleum product
sales less direct operating costs (including cost of refined
products sold and refinery operating expenses) and the JMA profit
share.
Revenue from Operations
.
Primarily consists of refined petroleum product sales, but also
includes tank rental and pipeline transportation revenue.
Excise and other taxes that are collected from customers and
remitted to governmental authorities are not included in
revenue.
Total Refinery Production
. Refers to the volume processed as
output through the Nixon Facility. Refinery production includes
finished petroleum products, such as jet fuel and exportable
low-sulfur diesel, and intermediate petroleum products, such as
LPG, naphtha, HOBM and AGO.
Total Refinery Throughput
.
Refers to the volume processed as
input through the Nixon Facility. Refinery throughput includes
crude oil and condensate and other feedstocks.
36
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
37
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.)
Remainder of Page Intentionally Left Blank
38
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.)
39
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.)
Remainder
of Page Intentionally Left Blank
40
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
41
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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,
m
anagement 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.)
42
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
Remainder
of Page Intentionally Left Blank
43
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
44
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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
|
(1) Represents construction-related vendor invoices awaiting
payment from the loan disbursement account.
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.)
45
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
46
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
47
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
48
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
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.
Remainder of Page Intentionally Left Blank
49
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
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.
Remainder
of Page Intentionally Left Blank
50
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
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
51
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
52
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
|
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
|
See
accompanying notes to consolidated financial
statements.
53
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
REVENUE
FROM OPERATIONS
|
|
|
|
Refined
petroleum product sales
|
$
165,413,778
|
$
220,438,588
|
|
Tank
rental revenue
|
2,366,548
|
1,147,568
|
|
Pipeline
operations
|
74,990
|
146,464
|
|
Total
revenue from operations
|
167,855,316
|
221,732,620
|
|
|
|
|
|
COST
OF OPERATIONS
|
|
|
|
Cost
of refined products sold
|
161,714,526
|
193,216,959
|
|
Refinery
operating expenses
|
12,040,676
|
11,683,658
|
|
Joint
Marketing Agreement profit share
|
359,260
|
5,820,329
|
|
Pipeline
operating expenses
|
340,550
|
(142,250
)
|
|
Lease
operating expenses
|
45,043
|
30,023
|
|
General
and administrative expenses
|
2,708,594
|
1,525,577
|
|
Depletion,
depreciation and amortization
|
1,935,644
|
1,647,586
|
|
Impairment
expense
|
968,684
|
-
|
|
Bad
debt expense (recovery)
|
(139,868
)
|
139,874
|
|
Other
operating expenses
|
-
|
-
|
|
Accretion
expense
|
112,744
|
211,375
|
|
Total
cost of operations
|
180,085,853
|
214,133,131
|
|
Income
(loss) from operations
|
(12,230,537
)
|
7,599,489
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
Easement,
interest and other income
|
1,924,893
|
980,266
|
|
Interest
and other expense
|
(1,854,567
)
|
(1,742,214
)
|
|
Total
other expense
|
70,326
|
(761,948
)
|
|
Income
(loss) before income taxes
|
(12,160,211
)
|
6,837,541
|
|
Income
tax expense
|
(3,607,237
)
|
(2,434,302
)
|
|
Net
income (loss)
|
$
(15,767,448
)
|
$
4,403,239
|
|
|
|
|
|
Income
(loss) per common share:
|
|
|
|
Basic
|
$
(1.51
)
|
$
0.42
|
|
Diluted
|
$
(1.51
)
|
$
0.42
|
|
|
|
|
|
Weighted
average number of common shares outstanding:
|
|
|
|
Basic
|
10,464,061
|
10,451,832
|
|
Diluted
|
10,464,061
|
10,451,832
|
See
accompanying notes to consolidated financial
statements.
54
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
|
Common
Stock
|
|
|
|
|
||
|
|
|
|
Additional
|
|
|
Total
|
|
|
|
|
|
Paid-In
|
Accumulated
|
Treasury Stock
|
Stockholders’
|
|
|
|
Shares
Issued
|
Par
Value
|
Capital
|
Deficit
|
Shares
|
Cost
|
Equity
|
|
Balance
at December 31, 2014
|
10,599,444
|
$
105,995
|
$
36,718,781
|
$
(8,057,308
)
|
(150,000
)
|
$
(800,000
)
|
$
27,967,468
|
|
|
|
|
|
|
|
|
|
|
Common
stock issued for services
|
4,358
|
43
|
19,956
|
-
|
-
|
-
|
19,999
|
|
Net
income
|
-
|
-
|
-
|
4,403,239
|
-
|
-
|
4,403,239
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2015
|
10,603,802
|
$
106,038
|
$
36,738,737
|
$
(3,654,069
)
|
(150,000
)
|
$
(800,000
)
|
$
32,390,706
|
|
|
|
|
|
|
|
|
|
|
Common
stock issued for services
|
20,912
|
210
|
79,791
|
-
|
-
|
-
|
80,001
|
|
Net
loss
|
-
|
-
|
-
|
(15,767,448
)
|
-
|
-
|
(15,767,448
)
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2016
|
10,624,714
|
$
106,248
|
$
36,818,528
|
$
(19,421,517
)
|
(150,000
)
|
$
(800,000
)
|
$
16,703,259
|
See
accompanying notes to consolidated financial
statements.
Remainder
of Page Intentionally Left Blank
55
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
OPERATING
ACTIVITIES
|
|
|
|
Net income (loss)
|
$
(15,767,448
)
|
$
4,403,239
|
|
Adjustments to reconcile net income (loss) to net cash
|
|
|
|
provided
by (used in) operating activities:
|
|
|
|
Depletion,
depreciation and amortization
|
1,935,644
|
1,647,586
|
|
Unrealized
loss (gain) on derivatives
|
(183,400
)
|
679,300
|
|
Deferred
tax expense
|
3,607,237
|
2,152,869
|
|
Amortization
of debt issue costs
|
128,485
|
544,607
|
|
Accretion
expense
|
112,744
|
211,375
|
|
Common
stock issued for services
|
80,001
|
19,999
|
|
Recovery
of bad debt
|
(139,868
)
|
139,874
|
|
Impairment
of fixed assets
|
968,684
|
-
|
|
Changes
in operating assets and liabilities
|
|
|
|
Accounts
receivable
|
3,574,947
|
2,883,058
|
|
Accounts
receivable, related party
|
(1,161,589
)
|
-
|
|
Prepaid
expenses and other current assets
|
95,449
|
(168,232
)
|
|
Deposits
and other assets
|
1,073,457
|
293,084
|
|
Inventory
|
5,732,780
|
(4,607,667
)
|
|
Accounts
payable, accrued expenses and other liabilities
|
(4,006,063
)
|
(272,062
)
|
|
Accounts
payable, related party
|
69,600
|
(874,168
)
|
|
Net
cash provided by (used in) operating activities
|
(3,879,340
)
|
7,052,862
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
Capital
expenditures
|
(14,100,897
)
|
(11,370,993
)
|
|
Net
cash used in investing activities
|
(14,100,897
)
|
(11,370,993
)
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
Proceeds
from issuance of debt
|
7,118,969
|
38,000,000
|
|
Payments
on debt
|
(3,701,616
)
|
(12,881,612
)
|
|
Payment
of debt issue costs
|
-
|
(2,456,352
)
|
|
Net
cash provided by financing activities
|
3,417,353
|
22,662,036
|
|
Net
increase (decrease) in cash, cash equivalents, and restricted
cash
|
(14,562,884
)
|
18,343,905
|
|
|
|
|
|
CASH,
CASH EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF
PERIOD
|
20,645,652
|
2,301,747
|
|
CASH,
CASH EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD
|
$
6,082,768
|
$
20,645,652
|
|
|
|
|
|
Supplemental
Information:
|
|
|
|
Non-cash
investing and financing activities:
|
|
|
|
Financing
of capital expenditures via accounts payable
|
$
2,286,082
|
$
873,665
|
|
Interest
paid
|
$
2,357,237
|
$
1,608,808
|
|
Income
taxes paid
|
$
-
|
$
139,500
|
See
accompanying notes to consolidated financial
statements.
56
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Nature of Operations
. Blue Dolphin Energy Company
(“Blue Dolphin,”) is primarily an independent refiner
and marketer of petroleum products. Our primary asset is a
15,000-bpd crude oil and condensate processing facility that is in
Nixon, Texas (the “Nixon Facility”). As part of our
refinery business segment, we conduct petroleum storage and
terminaling operations under third-party lease agreements at the
Nixon Facility. We also own pipeline assets and have leasehold
interests in oil and gas properties. (See “Note (4) Business
Segment Information” for further discussion of our business
segments.)
Structure and Management
.
Blue Dolphin was formed as a
Delaware corporation in 1986. We are currently controlled by
Lazarus Energy Holdings, LLC (“LEH”), which owns
approximately 81% of our common stock, par value $0.01 per share
(the “Common Stock). LEH manages and operates all our
properties pursuant to an Operating Agreement (the “Operating
Agreement”). Jonathan Carroll is Chairman of the Board of
Directors (the “Board”), Chief Executive Officer, and
President of Blue Dolphin, as well as a majority owner of LEH. (See
“Note (8) Related Party Transactions,” “Note (10)
Long-Term Debt, Net,” and “Note (20) Commitments and
Contingencies – Financing Agreements” for additional
disclosures related to LEH, the Operating Agreement, and Jonathan
Carroll.)
Our
operations are conducted through the following active
subsidiaries:
●
Lazarus Energy,
LLC, a Delaware limited liability company
(“LE”).
●
Lazarus Refining
& Marketing, LLC, a Delaware limited liability company
(“LRM”).
●
Blue Dolphin Pipe
Line Company (“BDPL”), a Delaware
corporation.
●
Blue Dolphin
Petroleum Company, a Delaware corporation.
●
Blue Dolphin
Services Co., a Texas corporation.
See
"Part I, Item 1. Business and Item 2. Properties” within this
Annual Report on Form 10-K (this “Annual Report”) for
additional information regarding our operating subsidiaries,
principal facilities, and assets.
References
in this Annual Report to “we,” “us,” and
“our” are to Blue Dolphin and its subsidiaries unless
otherwise indicated or the context otherwise requires.
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:
●
Net
Losses – 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. The $1.93 per share decrease in net
income between the periods was the result of lower margins on
refined petroleum products, lower refinery throughput, higher
refinery operating expenses, and income tax expense. Margins on
refined petroleum products decreased primarily because of lower
crack spreads.
57
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
●
Working Capital Deficits – 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 described above
.
●
Adverse Change in Relationship with Genesis
Energy, LLP (“Genesis”) and GEL Tex Marketing, LLC
(“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. We currently have a contract-related dispute with
GEL related to certain of these agreements. 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.
●
Crude Supply Issues – Historically, we
purchased light crude oil and condensate for the Nixon Facility
from GEL pursuant to a Crude Oil Supply and Throughput Services
Agreement (the “Crude Supply Agreement”). As noted
above, 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 a significant decrease in refinery throughput
and refined petroleum product sales for the year ended December 31,
2016. Consequently, 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 adequate supplies
of crude oil and condensate is dependent on our liquidity and
access to capital, which have been adversely affected by the
contract-related dispute with GEL and other factors, as noted
above.
●
Financial
Covenant Defaults – At December 31, 2016, we were in
violation of certain financial covenants in secured loan agreements
with Sovereign. 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 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.
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.
58
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
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:
●
●
–
Key Relationships
– Relationship with Genesis and GEL
–
Results of
Operations – Non-GAAP Financial Measures
●
–
Note (10) Long-Term
Debt, Net
–
Note (20)
Commitments and Contingencies – Genesis Agreements and Legal
Matters
–
Note (21)
Subsequent Events
|
(2)
|
Basis of Presentation
|
Our
consolidated financial statements include Blue Dolphin and its
subsidiaries. Significant intercompany transactions have been
eliminated in consolidation. The accompanying consolidated
financial statements have been prepared in accordance with U.S.
generally accepted accounting principles (“GAAP”) for
consolidated financial information pursuant to the rules and
regulations of the SEC under Regulation S-X and the instructions to
Form 10-K. In management’s opinion, all adjustments
considered necessary for a fair presentation have been included,
disclosures are adequate, and the presented information is not
misleading.
|
(3)
|
Significant Accounting Policies
|
The
summary of significant accounting policies of Blue Dolphin is
presented to assist in understanding our consolidated financial
statements. Our consolidated financial statements and accompanying
notes are representations of management who is responsible for
their integrity and objectivity. These accounting policies conform
to GAAP and have been consistently applied in the preparation of
our consolidated financial statements.
Use of Estimates
.
We have made several estimates and
assumptions related to the reporting of our consolidated assets and
liabilities and to the disclosure of contingent assets and
liabilities to prepare these consolidated financial statements in
conformity with GAAP. We believe our current estimates are
reasonable and appropriate, however, actual results could differ
from those estimated.
Cash and Cash Equivalents
.
Cash and cash equivalents
represent liquid investments with an original maturity of three
months or less. Cash balances are maintained in depository and
overnight investment accounts with financial institutions that, at
times, may exceed insured deposit limits. We monitor the financial
condition of the financial institutions and have experienced no
losses associated with these accounts. Cash and cash equivalents
totaled $1,152,628 and $1,853,875 at December 31, 2016 and 2015,
respectively.
Restricted Cash
.
At December 31, 2016, total
restricted cash was $4,930,140, comprised of restricted cash
(current portion) totaling $3,347,835 and restricted cash,
noncurrent totaling $1,582,305. At December 31, 2015, total
restricted cash was $18,791,777, comprised of restricted cash
(current portion) totaling $3,175,299 and restricted cash,
noncurrent totaling $15,616,478.
Restricted cash (current portion)
primarily represents: (i) amounts held in our disbursement account
with Sovereign attributable to construction invoices awaiting
payment from that account, (ii) a payment reserve account held by
Sovereign as security for payments under a loan agreement, and
(iii) a construction contingency account under which Sovereign will
fund contingencies. Restricted cash, noncurrent represents funds
held in the Sovereign disbursement account for payment of future
construction related expenses to build new petroleum storage tanks.
(See “Note (10) Long-Term Debt, Net” for additional
disclosures related to our loan agreements with
Sovereign.)
59
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Accounts Receivable and Allowance for Doubtful
Accounts
.
Accounts receivable are customer
obligations due under normal trade terms. The allowance for
doubtful accounts represents our estimate of the amount of probable
credit losses existing in our accounts receivable. We have a
limited number of customers with individually large amounts due on
any given date. Any unanticipated change in any one of these
customers’ credit worthiness or other matters affecting the
collectability of amounts due from such customers could have a
material adverse effect on our results of operations in the period
in which such changes or events occur. We regularly review all our
aged accounts receivable for collectability and establish an
allowance for individual customer balances as necessary. Allowance
for doubtful accounts totaled $0 and $139,868 at December 31, 2016
and 2015, respectively.
Inventory
.
The
nature of our business requires us to maintain inventory, which
primarily consists of refined petroleum products and chemicals. Our
overall inventory is valued at lower of cost or market with costs
being determined by the average cost method. If the market value of
our refined petroleum product inventories declines to an amount
less than our average cost, we record a write-down of inventory and
an associated adjustment to cost of refined products sold. (See
“Note (6) Inventory” for additional disclosures related
to our inventory.)
Derivatives
.
We
are exposed to commodity prices and other market risks including
gains and losses on certain financial assets because of our
inventory risk management policy. Under our inventory risk
management policy, commodity futures contracts may be used to
mitigate the change in value for certain of our refined petroleum
product inventories subject to market price fluctuations. The
physical inventory volumes are not exchanged and these contracts
are net settled with cash.
Although
these commodity futures contracts are not subject to hedge
accounting treatment under Financial Accounting Standards Board
(the “FASB”) Accounting Standards Codification
(“ASC”) guidance, we record the fair value of these
hedges in our consolidated balance sheet each financial reporting
period because of contractual arrangements under which we are
exposed to the potential gains or losses. We recognize all
commodity hedge positions as either current assets or current
liabilities in our consolidated balance sheets, and those
instruments are measured at fair value. Changes in the fair value
from financial reporting period to financial reporting period are
recognized in our consolidated statements of operations. Net gains
or losses associated with these transactions are recognized within
cost of refined products sold in our consolidated statements of
operations using mark-to-market accounting.
(See
“Note (18) Fair Value Measurement” and “Note (19)
Inventory Risk Management” for additional disclosures related
to derivatives.)
Property and Equipment
.
Refinery and Facilities
. Additions to refinery and
facilities assets are capitalized. Expenditures for repairs and
maintenance are expensed as incurred and are included as operating
expenses under the Operating Agreement. Management expects to
continue making improvements to the Nixon Facility based on
technological advances.
We record refinery and facilities at cost less any adjustments for
depreciation or impairment.
Adjustment of the asset and the
related accumulated depreciation accounts are made for the refinery
and facilities asset’s retirement and disposal, with the
resulting gain or loss included in the consolidated statements of
operations. For financial reporting purposes, depreciation of
refinery and facilities assets is computed using the straight-line
method using an estimated useful life of 25 years beginning when
the refinery and facilities assets are placed in service. We did
not record any impairment of our refinery and facilities assets for
any period presented.
Pipelines and Facilities
. We record pipelines and facilities
at cost less any adjustments for depreciation or impairment.
Depreciation is computed using the straight-line method over
estimated useful lives ranging from 10 to 22 years. In accordance
with FASB ASC guidance on accounting for the impairment or disposal
of long-lived assets, we 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.
60
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
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.
Oil and Gas Properties
. We account for our oil and gas
properties using the full-cost method of accounting, whereby all
costs associated with acquisition, exploration and development of
oil and gas properties, including directly related internal costs,
are capitalized on a cost center basis. Amortization of
such costs and estimated future development costs are determined
using the unit-of-production method. Our oil and gas properties had
no production during the 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.
Construction in Progress
. Construction in progress
expenditures, which relate to construction and refurbishment
activities at the Nixon Facility, are capitalized as incurred.
Depreciation begins once the asset is placed in
service.
(See
“Note (7) Property, Plant and Equipment, Net” for
additional disclosures related to our refinery and facilities
assets, oil and gas properties, pipelines and facilities assets,
and construction in progress.)
Intangibles – Other
. We have an intangible asset
consisting of the Blue Dolphin Energy Company trade name in the
amount of $303,346 on our consolidated balance sheets at December
31, 2016 and 2015. We have determined the trade name to have an
indefinite useful life. We account for other intangible assets
under FASB ASC guidance related to intangibles, goodwill, and
other. Under the guidance, we test intangible assets with
indefinite lives annually for impairment. Management performed its
regular annual impairment testing of trade name in the fourth
quarter of 2016. Upon completion of that testing, we determined
that no impairment was necessary at December 31, 2016.
Debt Issue Costs
. We have debt issue costs related to
certain refinery and facilities assets debt. Debt issue costs are
capitalized and amortized over the term of the related debt using
the straight-line method, which approximates the effective interest
method. When a loan is paid in full, any unamortized financing
costs are removed from the related asset accounts and expensed as
interest expense. Debt issue costs are reflected as a direct
reduction of the associated debt on our consolidated balance
sheets. See “Note (10) Long-Term Debt, Net” for
additional disclosures related to debt issue costs.
Revenue Recognition
.
Refined Petroleum Products Revenue
. Regarding our finished
products, low-sulfur diesel is sold to customers that export to
Mexico and jet fuel is sold to LEH for resale to a government
agency. Our intermediate products, including LPG, naphtha, HOBM,
and AGO, are primarily sold in nearby markets to wholesalers and
refiners for further blending and processing. Revenue from refined
petroleum products sales is recognized when sales prices are fixed
or determinable, collectability is reasonably assured, and title
passes. Title passage occurs when refined petroleum products are
delivered in accordance with the terms of the respective sales
agreements, and customers assume the risk of loss when title is
transferred. Transportation, shipping, and handling costs incurred
are included in cost of refined products sold. Excise and other
taxes that are collected from customers and remitted to
governmental authorities are not included in revenue.
Tank Rental Revenue
. Tank rental fees are invoiced monthly
in accordance with the terms of the related lease agreement and
recognized in revenue as earned.
Easement Revenue
. Land easement revenue is recognized
monthly as earned and is included in other income.
Pipeline Transportation Revenue
. Revenue from our pipeline
operations is derived from fee-based contracts and is typically
based on transportation fees per unit of volume transported
multiplied by the volume delivered. Revenue is recognized when
volumes have been physically delivered for the customer through the
pipeline.
61
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Deferred Revenue
. In 2014, we increased the ownership
interest in our pipeline assets from approximately 83% to 100%
pursuant to an Asset Sale Agreement (the “Purchase
Agreement”) with a former partner. Pursuant to the Purchase
Agreement, the former partner paid us $100,000 in cash, and a
surety company $850,000 in cash as collateral for supplemental
pipeline bonds for our benefit in exchange for the payment and
discharge of all payables, claims, and obligations related to the
pipeline assets. We recorded the amount received for our benefit
related to the supplemental pipeline bonds as deferred revenue. We
recognized the deferred revenue on a straight-line basis through
December 31, 2018, the expected retirement date of the associated
assets. In 2015, a significant portion of the remaining deferred
revenue was recognized as a result of abandoning a segment of the
pipeline assets. (See “Part I, Business – Governmental
Regulation – Offshore Safety and Environmental Oversight
– Decommissioning Requirements” in our Annual Report
for a discussion related to supplemental pipeline
bonds.)
Income Taxes
. We account for income taxes under FASB ASC
guidance related to income taxes, which requires recognition of
income taxes based on amounts payable with respect to the current
yearly period and the effects of deferred taxes for the expected
future tax consequences of events that have been included in our
financial statements or tax returns. Under this method,
deferred tax assets and liabilities are determined based on the
differences between the financial accounting and tax basis of
assets and liabilities, as well as for operating losses and tax
credit carryforwards using enacted tax rates in effect for the year
in which the differences are expected to
reverse.
As of
each reporting date, management considers new evidence, both
positive and negative, to determine the realizability of deferred
tax assets. Management considers whether it is more likely than not
that a portion or all the deferred tax assets will be realized,
which is dependent upon the generation of future taxable income
prior to the expiration of any net operating loss
(“NOL”) carryforwards. When management determines that
it is more likely than not that a tax benefit will not be realized,
a valuation allowance is recorded to reduce deferred tax assets. A
significant piece of objective negative evidence evaluated was the
cumulative loss incurred over the three-year period ended December
31, 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
“Note (16) Income Taxes” for further information
related to income taxes.)
Impairment or Disposal of Long-Lived Assets
. In accordance
with FASB ASC guidance on accounting for the impairment or disposal
of long-lived assets, we periodically evaluate our long-lived
assets for impairment. Additionally, we evaluate our long-lived
assets when events or circumstances indicate that the carrying
value of these assets may not be recoverable. The carrying value is
not recoverable if it exceeds the sum of the undiscounted cash
flows expected to result from the use and eventual disposition of
the asset or group of assets. If the carrying value exceeds the sum
of the undiscounted cash flows, an impairment loss equal to the
amount by which the carrying value exceeds the fair value of the
asset or group of assets is recognized. Significant management
judgment is required in the forecasting of future operating results
that are used in the preparation of projected cash flows and,
should different conditions prevail or judgments be made, material
impairment charges could be necessary.
Asset Retirement Obligations
. FASB ASC guidance related to
asset retirement obligations (“AROs”) requires that a
liability for the discounted fair value of an ARO be recorded in
the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted towards its future
value each period, and the capitalized cost is depreciated over the
useful life of the related asset. If the liability is settled for
an amount other than the recorded amount, a gain or loss is
recognized.
Management
has concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facilities assets arises
and a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
62
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
We
recorded an ARO liability related to future asset retirement costs
associated with dismantling, relocating, or disposing of our
offshore platform, pipeline systems, and related onshore
facilities, as well as for plugging and abandoning wells and
restoring land and sea beds. We developed these cost estimates for
each of our assets based upon regulatory requirements, structural
makeup, water depth, reservoir characteristics, reservoir depth,
equipment demand, current retirement procedures, and construction
and engineering consultations. Because these costs typically extend
many years into the future, estimating future costs are difficult
and require management to make judgments that are subject to future
revisions based upon numerous factors, including changing
technology, political, and regulatory environments. We review our
assumptions and estimates of future abandonment costs on an annual
basis.
(See
“Note (11) Asset Retirement Obligations” for additional
information related to our AROs.)
Computation of Earnings Per Share
. We apply the provisions
of FASB ASC guidance for computing earnings per share
(“EPS”). The guidance requires the presentation of
basic EPS, which excludes dilution and is computed by dividing net
income available to common stockholders by the weighted-average
number of shares of common stock outstanding for the period. The
guidance requires dual presentation of basic EPS and diluted EPS on
the face of our consolidated statements of operations and requires
a reconciliation of the denominator of basic EPS and diluted EPS.
Diluted EPS is computed by dividing net income available to common
stockholders by the diluted weighted average number of common
shares outstanding, which includes the potential dilution that
could occur if securities or other contracts to issue shares of
common stock were converted to common stock that then shared in the
earnings of the entity.
The
number of shares related to options, warrants, restricted stock,
and similar instruments included in diluted EPS is based on the
“Treasury Stock Method” prescribed in FASB ASC guidance
for computation of EPS. This method assumes theoretical repurchase
of shares using proceeds of the respective stock option or warrant
exercised, and, for restricted stock, the amount of compensation
cost attributed to future services that has not yet been recognized
and the amount of any current and deferred tax benefit that would
be credited to additional paid-in-capital upon the vesting of the
restricted stock, at a price equal to the issuer’s average
stock price during the related earnings period. Accordingly, the
number of shares includable in the calculation of EPS in respect of
the stock options, warrants, restricted stock, and similar
instruments is dependent on this average stock price and will
increase as the average stock price increases. (See “Note
(17) Earnings Per Share” for additional information related
to EPS.)
Stock-Based Compensation
. In accordance with FASB ASC
guidance for stock-based compensation, share-based payments to
directors, including the issuance of restricted common stock, are
measured at fair value as of the date of grant and are expensed in
our consolidated statements of operations over the service period
(generally the vesting period).
Treasury Stock
. We account for treasury stock under the cost
method. When treasury stock is re-issued, the net change in share
price after acquisition of the treasury stock is recognized as a
component of additional paid-in-capital in our consolidated balance
sheets. (See “Note (13) Treasury Stock” for additional
disclosures related to treasury stock.)
New Pronouncements Adopted
. The FASB issues an Accounting
Standards Update (“ASU”) to communicate changes to the
FASB ASC, including changes to non-authoritative SEC content. For
the 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 requires 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.
63
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
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.
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 2014-15 affected our disclosure requirements.
New Pronouncements Issued, Not Yet Effective
. The following
are recently issued, but not yet effective, ASU’s that may
influence our consolidated financial position, results of
operations, or cash flows:
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of
Certain Cash Receipts and Cash Payments.
In August 2016, FASB issued ASU 2016-15. This
guidance addresses eight specific cash flow issues to reduce future
diversity of practice. For public business entities, the amendments
in ASU 2016-15 are effective for fiscal years beginning after
December 15, 2018, and interim periods within fiscal years
beginning after December 15, 2019. Early adoption is permitted. We
are evaluating the impact that adoption of this guidance will have
on our consolidated statements of cash flows.
ASU 2016-13,
Financial Instruments —
Credit Losses (Topic 326): Measurement of Credit Losses on
Financial Instruments)
. In June
2016, FASB issued ASU 2016-13.
This
guidance updates the current impairment model to incorporate both
expected and incurred credit losses, eliminating potential
overstatements of assets and resulting in more timely recognition
of losses.
For a public business
entity, the amendments in ASU 2016-13 are effective for fiscal
years beginning after December 15, 2019, including interim periods
within those fiscal years. Early application as of the fiscal years
beginning after December 15, 2018, including interim periods within
those fiscal years, is permitted. We are evaluating the impact that
adoption of this guidance will have on our consolidated financial
statements.
ASU 2016-02,
Leases (Topic
842)
. In February 2016, FASB
issued ASU 2016-02.
This
guidance i
ncreases transparency and
comparability among organizations by recognizing lease assets and
lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. For a public business
entity, the amendments in ASU 2016-02 are effective for fiscal
years beginning after December 15, 2018, including interim periods
within those fiscal years. Early application is permitted. We are
evaluating the impact that adoption of this guidance will have on
our consolidated balance sheets.
ASU 2015-11,
Inventory
(Topic 330):
Simplifying
the Measurement of Inventory
. In July 2015, FASB issued ASU
2015-11. Current guidance requires an entity to measure inventory
at the lower of cost or market. Market could be replacement cost,
net realizable value, or net realizable value less an approximately
normal profit margin. Under ASU 2015-11, an entity should measure
inventory at the lower of cost or net realizable value. Net
realizable value is the estimated selling price in the ordinary
course of business, less reasonably predictable costs of
completion, disposal, and transportation. Amendments under ASU
2015-11 more closely align the measurement of inventory in GAAP
with the measurement of inventory in International Financial
Reporting Standards. For public business entities, ASU 2015-11 is
effective for fiscal years beginning after December 15, 2016,
including interim periods within those fiscal years. ASU 2015-11
should be applied prospectively with earlier application permitted
as of the beginning of an interim or annual reporting period.
We do not anticipate adoption of this
guidance to have a material effect on our consolidated financial
statements.
64
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
ASU 2014-09,
Revenue from
Contracts with Customers (Topic 606)
. In May 2014, FASB and
the International Accounting Standards Board (the
“IASB”) issued ASU 2014-09, a converged standard on
recognition of revenue from contracts with customers. In June 2014,
the FASB and the IASB (collectively, the “Accounting
Boards”) formed the FASB-IASB Joint Transition Resource Group
for Revenue Recognition (the “TRG”). The primary
objective of the TRG is to inform the Accounting Boards about
potential implementation issues that could arise when organizations
implement the new revenue guidance. Resultant ASU’s as part
of the TRG process associated with ASU 2014-09
include:
●
ASU 2015-14,
R
evenue from Contracts with Customers (Topic
606): Deferral of the Effective Date;
●
ASU 2016-08,
Revenue from Contracts with Customers (Topic
606): Principal Versus Agent Considerations (Reporting Revenue
Gross Versus Net);
●
ASU 2016-10
,
Revenue from Contracts with Customers (Topic
606): Identifying Performance Obligations and
Licensing;
●
ASU 2016-11,
Revenue Recognition (Topic 605)
and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance
Because of Accounting Standards Updates 2014-09 and 2014-16
Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting
(SEC Update);
●
ASU 2016-12,
Revenue from Contracts with
Customers (Topic 606): Narrow-Scope Improvements and Practical
Expedients;
and
●
ASU 2016-20,
Technical Corrections and
Improvements to Topic 606, Revenue from Contracts with
Customers
.
We are
evaluating the impact that adoption of ASU 2014-09, ASU 2015-14,
ASU 2016-08, ASU 2016-10, ASU 2016-11, ASU 2016-12, and ASU
2016-20, all of which relate to Revenue from Contracts with
Customers (Topic 606), will have on our consolidated financial
statements.
Other new pronouncements issued but not yet effective are not
expected to have a material impact on our financial position,
results of operations, or liquidity.
Reclassification
. We have
reclassified certain prior year amounts to conform to our 2016
presentation.
Remainder of Page Intentionally Left Blank
65
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(4)
|
Business
Segment Information
|
We have two reportable business segments: (i) Refinery Operations
and (ii) Pipeline Transportation. Business activities related to
our Refinery Operations business segment are conducted at the Nixon
Facility. Business activities related to our Pipeline
Transportation business segment are primarily conducted in the Gulf
of Mexico through our pipeline assets and leasehold interests in
oil and gas properties.
Business
segment information for the periods indicated (and as of the dates
indicated), was as follows:
|
|
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
(3)
|
(7,560,490
)
|
522,576
|
(983,112
)
|
(8,021,026
)
|
16,182,801
|
413,033
|
(555,929
)
|
16,039,905
|
|
Less: JMA Profit Share
(4)
|
(359,260
)
|
-
|
-
|
(359,260
)
|
(5,820,329
)
|
-
|
-
|
(5,820,329
)
|
|
EBITDA
(3)
|
$
(7,919,750
)
|
$
522,576
|
$
(983,112
)
|
|
$
10,362,472
|
$
413,033
|
$
(555,929
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and
|
|
|
|
|
|
|
|
|
|
amortization
|
|
|
|
(1,935,644
)
|
|
|
|
(1,647,586
)
|
|
Interest
expense, net
|
|
|
|
(1,844,281
)
|
|
|
|
(1,734,449
)
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
|
|
(12,160,211
)
|
|
|
|
6,837,541
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax expense
|
|
|
|
(3,607,237
)
|
|
|
|
(2,434,302
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
|
|
$
(15,767,448
)
|
|
|
|
$
4,403,239
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
$
16,386,979
|
$
-
|
$
-
|
$
16,386,979
|
$
12,244,658
|
$
-
|
$
-
|
$
12,244,658
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets
(5)
|
$
74,236,629
|
$
763,596
|
$
359,793
|
$
75,360,018
|
$
82,605,078
|
$
2,338,107
|
$
4,077,529
|
$
89,020,714
|
|
(1)
|
Operation
cost within the Refinery Operations and Pipeline Transportation
segments includes related general, administrative, and accretion
expenses. Operation cost within the Pipeline Transportation segment
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 Land II, Inc.
(“FLNG”) easement revenue. (See “Note (20)
Commitments and Contingencies – FLNG Easement
Agreements” for further discussion related to
FLNG.)
|
|
(3)
|
Adjusted EBITDA and EBITDA are non-GAAP financial measures. See
“Part II, Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations – Results of
Operations – Non-GAAP Financial Measures” for
additional information related to adjusted EBITDA and
EBITDA.
|
|
(4)
|
The JMA Profit Share represents the
GEL
Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement. (
See
“Note (20) Commitments and Contingencies – Genesis
Agreements” for further discussion related to the Joint
Marketing Agreement and the contract-related dispute with
GEL.)
|
|
(5)
|
Identifiable assets for the prior year period reflect
reclassification of debt issue costs as a reduction in long-term
debt to conform to the 2016 presentation.
|
66
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(5)
|
Prepaid Expenses and Other Current Assets
|
Prepaid
expenses and other current assets as of the dates indicated
consisted of the following:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Short-term
tax bond
|
$
505,000
|
$
-
|
|
Prepaid
exise taxes
|
292,338
|
-
|
|
Prepaid
insurance
|
248,853
|
315,120
|
|
Prepaid
related party operating expenses
|
-
|
624,570
|
|
Unrealized
hedging gains
|
-
|
-
|
|
|
|
|
|
|
$
1,046,191
|
$
939,690
|
|
(6)
|
Inventory
|
Inventory
as of the dates indicated consisted of the following:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Jet
fuel
|
$
964,124
|
$
309,850
|
|
Naphtha
|
533,580
|
5,007,576
|
|
HOBM
|
212,987
|
2,045,784
|
|
Chemicals
|
182,751
|
278,278
|
|
AGO
|
143,362
|
122,777
|
|
Crude
oil and condensate
|
26,123
|
7,152
|
|
Propane
|
11,318
|
17,860
|
|
LPG
mix
|
1,293
|
19,041
|
|
|
$
2,075,538
|
$
7,808,318
|
Remainder
of Page Intentionally Left Blank
67
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(7)
|
Property, Plant and Equipment, Net
|
Property,
plant and equipment, net, as of the dates indicated consisted of
the following:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Refinery
and facilities
|
$
50,814,309
|
$
40,195,928
|
|
Pipelines
and facilities
|
-
|
2,127,207
|
|
Onshore
separation and handling facilities
|
-
|
325,435
|
|
Land
|
602,938
|
602,938
|
|
Other
property and equipment
|
652,795
|
644,795
|
|
|
52,070,042
|
43,896,303
|
|
|
|
|
|
Less:
Accumulated depletion, depreciation, and amortization
|
(6,685,244
)
|
(6,234,161
)
|
|
|
45,384,798
|
37,662,142
|
|
|
|
|
|
Construction
in progress
|
16,939,665
|
11,179,670
|
|
|
|
|
|
|
$
62,324,463
|
$
48,841,812
|
We
capitalize interest cost incurred on funds used to construct
property, plant, and equipment. The capitalized interest is
recorded as part of the asset to which it relates and is
depreciated over the asset’s useful life. Interest cost
capitalized was $2,108,298 and $556,032 at December 31, 2016 and
2015, respectively.
|
(8)
|
Related Party Transactions
|
Agreement Summaries
. We are party to several agreements with
related parties. We believe these related party transactions were
consummated on terms equivalent to those that prevail in
arm's-length transactions. A summary of these agreements
follows:
LEH
. We are party to an Operating Agreement, a Product Sales
Agreement, a Terminal Services Agreement, a Loan and Security
Agreement, and a Promissory Note with LEH. LEH, our controlling
shareholder, owns approximately 81% of our Common Stock. Jonathan
Carroll, Chairman of the Board, Chief Executive Officer, and
President of Blue Dolphin, is the majority owner of
LEH.
Operating Agreement
. LEH manages and operates all our
properties pursuant to the Operating Agreement. The Operating
Agreement expires upon the earliest to occur of: (a) the date of
the termination of the Joint Marketing Agreement pursuant to its
terms, (b) August 2018, or (c) upon written notice of either party
to the Operating Agreement of a material breach of the Operating
Agreement by the other party. For services rendered under the
Operating Agreement, LEH receives reimbursements and fees as
follows:
●
Reimbursements –
For management
and operation of all properties excluding the Nixon Facility, LEH
is reimbursed at cost for all reasonable expenses incurred while
performing the services. Unsettled reimbursements to LEH are either
reflected within prepaid expenses and other current assets or
accounts payable, related party in our consolidated balance sheets.
(See “Note (5) Prepaid Expenses and Other Current
Assets” for additional disclosures with respect to prepaid
related party operating expenses.)
68
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
●
Fees –
For management and
operation of the Nixon Facility, LEH receives: (i) weekly payments
to cover direct expenses incurred, (ii) $0.25 for each bbl
processed at the Nixon Facility up to a maximum quantity of 10,000
bbls per day determined monthly, and (iii) $2.50 for each bbl
processed at the Nixon Facility more than 10,000 bbls per day
determined monthly. Amounts expensed as fees to LEH are reflected
within refinery operating expenses in our consolidated statements
of operations. Fees owed to LEH under the Operating Agreement, if
any, are reflected within accounts payable, related party in our
consolidated balance sheets.
Product Sales Agreement
. Under a Product Sales Agreement,
LEH purchases jet fuel and other products from the Nixon Facility
for resale to a government agency. The Product Sales Agreement
terminates on the earliest to occur of: (a) a one-year term
expiring March 31, 2017 plus a 30-day carryover or (b) delivery of
a maximum quantity of jet fuel as defined therein. Sales to LEH
under the Product Sales Agreement are reflected within refined
petroleum product sales in our consolidated statements of
operations.
Terminal Services Agreement
. Pursuant to a Terminal Services
Agreement, LEH leases a petroleum storage tank at the Nixon
Facility. The Terminal Services Agreement has an initial term of 12
months and automatically renews for additional terms of 6 months.
The parties may terminate the Terminal Services Agreement upon 45
days’ written notice. Rental fees received from LEH under the
Terminal Services Agreement are reflected within tank rental
revenue in our consolidated statements of operations.
Loan and Security Agreement
. In August 2016, BDPL entered a
loan and security agreement with LEH as evidenced by a promissory
note in the original principal amount of $4.0 million (the
“LEH Loan Agreement”). The LEH Loan Agreement matures
in August 2018, and accrues interest at rate of 16.00%. Under the
LEH Loan Agreement, BDPL will make payments to LEH of $500,000 per
year. A final balloon payment is due at maturity.
The
proceeds of the LEH Loan Agreement were used for working capital.
There are no financial maintenance covenants associated with the
LEH Loan Agreement. The LEH Loan Agreement is secured by certain
property owned by BDPL located in Brazoria County Texas (the "BDPL
Property"). Outstanding principal and interest less associated debt
issue costs owed to LEH under the LEH Loan Agreement are reflected
in long-term debt, related party, current portion and long-term
debt, related party, net of current portion in our consolidated
balance sheets.
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with LEH in the original principal amount of
$1,797,172 (the “LEH Note”). The LEH Note accrues
interest, compounded annually, at a rate of 8.00%. The principal
amount and any accrued but unpaid interest are due and payable in
January 2018. Under the LEH Note, prepayment, in whole or in part,
is permissible at any time and from time to time, without premium
or penalty. Outstanding principal and interest owed to LEH under
the LEH Note are reflected in long-term debt, related party, net of
current portion in our consolidated balance sheets. At December 31,
2016, the outstanding principal and interest on the LEH Note was
$0.
Ingleside Crude, LLC (“Ingleside”)
. We are party
to an Amended and Restated Tank Lease Agreement and a Promissory
Note with Ingleside. Ingleside is a related party of LEH and
Jonathan Carroll.
Amended and Restated Tank Lease Agreement
. Pursuant to an
Amended and Restated Tank Lease Agreement with Ingleside, we lease
petroleum storage tanks to meet periodic, additional storage needs.
The Amended and Restated Tank Lease Agreement had an initial term
of 30 days with automatic 30-day renewal periods. The parties may
terminate the tank lease agreement upon 30 days’ written
notice. Rental fees owed to Ingleside under the tank lease
agreement are reflected within accounts payable, related party in
our consolidated balance sheets. Amounts expensed as rental fees to
Ingleside under the Amended and Restated Tank Lease Agreement are
reflected within refinery operating expenses in our consolidated
statements of operations.
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with Ingleside in the original principal amount of
$679,385 (the “Ingleside Note”). The principal amount
of the Ingleside Note was increased by $50,000 in the fourth
quarter of 2016. The Ingleside Note accrues interest, compounded
annually, at a rate of 8.00%. The principal amount and any accrued
but unpaid interest are due and payable in January 2018. Under the
Ingleside Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty.
Outstanding principal and interest owed to Ingleside under the
Ingleside Note are reflected in long-term debt, related party, net
of current portion in our consolidated balance sheets. At December
31, 2016, the outstanding principal and interest on the Ingleside
Note was $722,278.
69
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Lazarus Marine Terminal I, LLC (“LMT”)
. We are
party to a Tolling Agreement with LMT. LMT is a related party of
LEH and Jonathan Carroll.
Tolling Agreement
. In May 2016, we entered a Tolling
Agreement with LMT to facilitate loading and unloading of our
petroleum products by barge at LMT’s dock facility in
Ingleside, Texas. The Tolling Agreement has a five-year term and
may be terminated at any time by the agreement of both parties. We
pay LMT a flat monthly reservation fee of $50,400. The monthly
reservation fee includes tolling volumes up to 84,000 gallons per
day. Tolling volumes more than 210,000 gallons per quarter are
billed to us at $0.02 per gallon. Amounts expensed as tolling fees
to LMT under the Tolling Agreement are reflected in cost of refined
products sold in our consolidated statements of
operations.
Jonathan Carroll
. We are party to Guaranty Fee Agreements
and a Promissory Note with Jonathan Carroll. Jonathan Carroll is
Chairman of the Board, Chief Executive Officer, and President of
Blue Dolphin.
Guaranty Fee Agreements
. Pursuant to Guaranty Fee
Agreements, Jonathan Carroll receives fees for providing his
personal guarantee on certain of our long-term debt. Jonathan
Carroll was required to guarantee repayment of funds borrowed and
interest accrued under certain loan agreements. Amounts owed to
Jonathan Carroll under Guaranty Fee Agreements are reflected within
accounts payable, related party in our consolidated balance sheets.
Amounts expensed related to Guarantee Fee Agreements are reflected
within interest and other expense in our consolidated statements of
operations. (See “Note (10) Long-Term Debt, Net” for
further discussion related to the Guaranty Fee
Agreements.)
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with Jonathan Carroll in the original principal
amount of $422,374 (the “Carroll Note”). The principal
amount of the Carroll Note was increased by $170,038 in the fourth
quarter of 2016. The Carroll Note accrues interest, compounded
annually, at a rate of 8.00%. The principal amount and any accrued
but unpaid interest are due and payable in January 2018. Under the
Carroll Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty.
Outstanding principal and interest owed to Jonathan Carroll under
the Carroll Note are reflected in long-term debt, related party,
net of current portion in our consolidated balance sheets. At
December 31, 2016, the outstanding principal and interest on the
Carroll Note was $592,412.
Financial Statements Impact
.
Consolidated Balance Sheets
. At December 31, 2016, accounts
receivable, related party from LEH totaled $1,161,589. Unsettled
reimbursements to LEH associated with the Operating Agreement and
reflected within prepaid expenses and other current assets as of
the dates indicated were as follows:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
LEH
|
$
-
|
$
624,570
|
|
|
$
-
|
$
624,570
|
Accounts
payable, related party to Ingleside associated with the Amended and
Restated Tank Lease Agreement and to LMT associated with the
Tolling Agreement as of the dates indicated was as
follows:
|
|
December 31, 2016
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Ingleside
|
$
-
|
$
300,000
|
|
LMT
|
369,600
|
-
|
|
|
$
369,600
|
$
300,000
|
70
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Long-term
debt, related party associated with the LEH Loan Agreement, LEH
Note, Ingleside Note, and Carroll Note as of the dates indicated
was as follows:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
LEH
|
$
4,000,000
|
$
-
|
|
Ingleside
|
722,278
|
-
|
|
Jonathan
Carroll
|
592,412
|
-
|
|
|
5,314,690
|
-
|
|
|
|
|
|
Less:
Long-term debt,
|
|
|
|
related party,
|
|
|
|
current portion
|
(500,000
)
|
-
|
|
|
$
4,814,690
|
$
-
|
Accrued
interest associated with the LEH Loan Agreement as of the dates
indicated was as follows:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
LEH
|
$
243,556
|
$
-
|
|
|
243,556
|
-
|
|
|
|
|
|
Less:
Interest payable,
|
|
|
|
current portion
|
(243,556
)
|
-
|
|
|
$
-
|
$
-
|
Consolidated Statements of Operations
. Related party revenue
from LEH associated with the Product Sales Agreement and Terminal
Services Agreement for the periods indicated was as
follows:
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Refined
petroleum product sales
|
|
|
|
LEH
|
$
43,904,790
|
$
-
|
|
Other
customers
|
121,508,988
|
220,438,588
|
|
Total
refined petroleum product sales
|
165,413,778
|
220,438,588
|
|
|
|
|
|
Tank
rental revenue
|
|
|
|
LEH
|
1,125,000
|
-
|
|
Other
customers
|
1,241,548
|
1,147,568
|
|
Total
tank rental revenue
|
2,366,548
|
1,147,568
|
|
|
|
|
|
Pipeline
operations
|
|
|
|
Other
customers
|
74,990
|
146,464
|
|
|
|
|
|
Total
revenue from operations
|
$
167,855,316
|
$
221,732,620
|
71
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Related
party cost of goods sold associated with the Tolling Agreement with
LMT for the periods indicated were as follows:
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
LMT
|
$
369,600
|
$
-
|
|
|
$
369,600
|
$
-
|
Related
party refinery operating expenses associated with the Operating
Agreement with LEH and the Amended and Restated Tank Lease
Agreement with Ingleside for the periods indicated were as
follows:
|
|
Years
Ended December 31,
|
|||
|
|
2016
|
2015
|
||
|
|
Amount
|
Per bbl
|
Amount
|
Per bbl
|
|
|
|
|
|
|
|
LEH
|
$
11,140,676
|
$
3.10
|
$
11,333,658
|
$
2.71
|
|
Ingleside
|
900,000
|
$
0.25
|
350,000
|
$
0.09
|
|
Jonathan
Carroll
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
$
12,040,676
|
$
3.35
|
$
11,683,658
|
$
2.80
|
Interest
expense associated with the LEH Loan Agreement and Guaranty Fee
Agreements for the periods indicated was as follows:
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Jonathan
Carroll
|
$
692,969
|
$
320,123
|
|
LEH
|
243,556
|
-
|
|
Ingleside
|
-
|
-
|
|
|
$
936,525
|
$
320,123
|
Remainder
of Page Intentionally Left Blank
72
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(9)
|
Accrued Expenses and Other Current Liabilities
|
Accrued
expenses and other current liabilities as of the dates indicated
consisted of the following:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Customer
deposits
|
$
450,000
|
$
157,714
|
|
Unearned
revenue
|
408,770
|
781,859
|
|
Other
payable
|
189,719
|
103,024
|
|
Board
of director fees payable
|
136,429
|
1,290,101
|
|
Insurance
|
67,783
|
-
|
|
Excise
and income taxes payable
|
24,187
|
388,364
|
|
Property
taxes
|
4,694
|
-
|
|
Genesis
JMA Profit Share payable
|
-
|
86,429
|
|
Transportation
and inspection
|
-
|
183,400
|
|
|
$
1,281,582
|
$
2,990,891
|
|
(10)
|
|
Effective
January 1, 2016, we adopted the provisions of the FASB ASC guidance
that requires debt issue costs to be presented as an offset to
their related debt. Accordingly, our consolidated balance sheet at
December 31, 2015 was changed to reclassify approximately $2.4
million previously reported debt issue costs as a direct deduction
of long-term debt.
Long-term
debt, net, which includes related-party, represents the outstanding
principal and interest of our long-term debt less associated debt
issue costs. Long-term debt, net as of the dates indicated
consisted of the following:
|
|
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 debt issue
|
|
|
|
costs and long-term debt, related party,
|
|
|
|
current portion
|
(32,212,336
)
|
(1,934,932
)
|
|
|
|
|
|
Less:
unamortized debt issue costs
|
(2,262,997
)
|
(2,391,482
)
|
|
|
|
|
|
|
$
6,114,690
|
$
32,846,254
|
73
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Debt
issue costs are capitalized and amortized over the terms of the
underlying loan using the effective-interest method. Debt
issue costs at December 31, 2016 and 2015 related to secured loan
agreements with Sovereign.
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
First
Term Loan Due 2034
|
$
1,673,545
|
$
1,673,545
|
|
Second
Term Loan Due 2034
|
767,673
|
767,673
|
|
|
|
|
|
Less:
Accumulated amortization
|
(178,221
)
|
(49,736
)
|
|
|
$
2,262,997
|
$
2,391,482
|
Amortization
expense, which is included in interest expense, was $128,233 and
$544,607 for the years ended December 31, 2016 and 2015,
respectively. Amortization expense for the year ended December 31,
2015 included $456,287 related to writing off debt issue costs
associated with the refinance of debt owed to American First
National Bank.
Accrued
interest associated with our long-term debt, net is reflected as
interest payable, current portion and long-term interest payable,
net of current portion in our consolidated balance sheets and
includes related party interest. Accrued interest as of the dates
indicated consisted of the following:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Notre
Dame Debt
|
$
1,691,383
|
$
1,482,801
|
|
LEH
Loan Agreement
|
243,556
|
-
|
|
Second
Term Loan Due 2034
|
44,984
|
39,193
|
|
First
Term Loan Due 2034
|
33,866
|
34,883
|
|
Capital
Leases
|
1,165
|
2,612
|
|
Term
Loan Due 2017
|
185
|
4,779
|
|
|
2,015,139
|
1,564,268
|
|
Less:
Interest payable, current portion
|
(323,756
)
|
(81,467
)
|
|
|
$
1,691,383
|
$
1,482,801
|
At
December 31, 2016, our expected future long-term debt payments were
as follow:
|
2017
|
$
34,475,333
|
|
2018
|
6,114,690
|
|
2019
|
-
|
|
2020
|
-
|
|
2021
|
-
|
|
Subsequent
to 2021
|
-
|
|
|
$
40,590,023
|
(See
“Note (8) Related Party Transactions” for additional
disclosures with respect to related party long-term
debt.)
74
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
First Term Loan Due 2034
. In 2015, LE entered a loan
agreement and related security agreement
with Sovereign as administrative
agent and lender,
providing
for a term loan in the principal amount of $25.0 million
(the “First Term Loan Due 2034”). The First Term Loan
Due 2034 matures in June 2034, has a current monthly payment of
principal and interest of $188,461, and accrues interest at a rate
based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to
a construction rider in the First Term Loan Due 2034, proceeds
available for use were placed in a disbursement account whereby
Sovereign makes payments for construction related expenses. Amounts
held in the disbursement account are reflected as restricted cash
(current portion) and restricted cash, noncurrent in our
consolidated balance sheets.
At
December 31, 2016, LE was in violation of the debt service coverage
ratio, the current ratio, and debt to net worth ratio financial
covenants related to the First Term Loan Due 2034. Consequently,
Sovereign could declare the amounts owed under the First Term Loan
Due 2034 immediately due and payable, exercise its rights with
respect to collateral securing LE’s obligations under the
loan agreement, and/or exercise any other rights and remedies
available. Sovereign waived the financial covenant defaults as of
the year ended December 31, 2016. However, the debt associated with
the loan 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. (See “Note (1)
Organization – Operating Risks-Going Concern” and
“Note (21) Subsequent Events” for additional
disclosures related to the First Term Loan Due 2034 and financial
covenant violations.)
As a
condition of the First Term Loan Due 2034, Jonathan Carroll was
required to guarantee r
epayment
of funds borrowed and
interest accrued under the loan. For his personal guarantee, LE
entered a Guaranty Fee Agreement with Jonathan Carroll whereby he
receives a fee equal to 2.00% per annum, paid monthly, of the
outstanding principal balance owed under the First Term Loan Due
2034.
For the years ended December 31,
2016 and 2015, guaranty fees related to the First Term Loan Due
2034 totaled $485,463 and $265,518, respectively. Guaranty fees are
recognized monthly as incurred and are included in interest and
other expense in our consolidated statements of operations.
LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due
2034. (See “Note (8) Related Party Transactions” for
additional disclosures related to LEH and Jonathan
Carroll.)
A
portion of the proceeds of the First Term Loan Due 2034 were used
to refinance approximately $8.5 million of debt owed under a
previous debt facility with American First National Bank. Remaining
proceeds are being used primarily to construct new petroleum
storage tanks at the Nixon Facility. The First Term Loan Due 2034
is secured by: (i) a first lien on all Nixon Facility business
assets (excluding accounts receivable and inventory), (ii)
assignment of all Nixon Facility contracts, permits, and licenses,
(iii) absolute assignment of Nixon Facility rents and leases,
including tank rental income, (iv) a $1.0 million payment reserve
account held by Sovereign, and (v) a pledge of $5.0 million of a
life insurance policy on Jonathan Carroll. The First Term Loan Due
2034 contains representations and warranties, affirmative,
restrictive, and financial covenants, as well as events of default
which are customary for bank facilities of this type.
Second Term Loan Due 2034
. In December 2015, LRM entered a
loan agreement and related security agreement with Sovereign as
administrative agent and lender, providing for a term loan in the
principal amount of $10.0 million (the “Second Term Loan Due
2034”). The Second Term Loan Due 2034 matures in December
2034, has a current monthly payment of principal and interest of
$74,111, and accrues interest at a rate based on the Wall Street
Journal Prime Rate plus 2.75%. Pursuant to a construction rider in
the Second Term Loan Due 2034, proceeds available for use were
placed in a disbursement account whereby Sovereign makes payments
for construction related expenses. Amounts held in the disbursement
account are reflected as restricted cash (current portion) and
restricted cash, noncurrent in our consolidated balance
sheets.
At
December 31, 2016, LRM was in violation of the debt service
coverage ratio, the current ratio, and the debt to net worth ratio
financial covenants related to the Second Term Loan Due 2034.
Consequently, Sovereign could declare the amounts owed under the
Second Term Loan Due 2034 immediately due and payable, exercise its
rights with respect to collateral securing LRM’s obligations
under the loan agreement, and/or exercise any other rights and
remedies available. Sovereign waived the financial covenant
defaults as of the year ended December 31, 2016. However, the debt
associated with the loan 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. (See “Note
(1) Organization – Operating Risks-Going Concern” and
“Note (21) Subsequent Events” for additional
disclosures related to the Second Term Loan Due 2034 and financial
covenant violations.)
75
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
As a
condition of the Second Term Loan Due 2034, Jonathan Carroll was
required to guarantee repayment of funds borrowed and interest
accrued under the loan. For his personal guarantee, LRM entered a
Guaranty Fee Agreement with Jonathan Carroll whereby he receives a
fee equal to 2.00% per annum, paid monthly, of the outstanding
principal balance owed under the Second Term Loan Due 2034. For the
years ended December 31, 2016 and 2015, guaranty fees related to
the Second Term Loan Due 2034 totaled $197,024 and $16,667,
respectively. Guaranty fees are recognized monthly as incurred and
are included in interest and other expense in our consolidated
statements of operations. LEH, LE and Blue Dolphin also guaranteed
the Second Term Loan Due 2034. (See “Note (8) Related Party
Transactions” for additional disclosures related to LEH and
Jonathan Carroll.)
A
portion of the proceeds of the Second Term Loan Due 2034 were used
to refinance a previous bridge loan from Sovereign in the amount of
$3.0 million. Remaining proceeds are being used primarily to
construct additional new petroleum storage tanks at the Nixon
Facility. The Second Term Loan Due 2034 is secured by: (i) a second
priority lien on the rights of LE in the Nixon Facility and the
other collateral of LE pursuant to a security agreement; (ii) a
first priority lien on the real property interests of LRM; (iii) a
first priority lien on all of LRM’s fixtures, furniture,
machinery and equipment; (iv) a first priority lien on all of
LRM’s contractual rights, general intangibles and
instruments, except with respect to LRM’s rights in its
leases of certain specified tanks, with respect to which Sovereign
has a second priority lien in such leases subordinate to a prior
lien granted by LRM to Sovereign to secure obligations of LRM under
the Term Loan Due 2017; and (v) all other collateral as described
in the security documents. The Second Term Loan Due 2034 contains
representations and warranties, affirmative, restrictive, and
financial covenants, as well as events of default which are
customary for bank facilities of this type.
LEH Loan Agreement
. The LEH Loan Agreement has a principal
amount of $4.0 million, matures in August 2018, and accrues
interest at rate of 16.00%. Under the LEH Loan Agreement, BDPL will
make payments of $500,000 per year to LEH. A final balloon payment
is due at maturity.
The
proceeds of the LEH Loan Agreement were used for working capital.
There are no financial maintenance covenants associated with the
LEH Loan Agreement. The LEH Loan Agreement is secured by the BDPL
Property. Outstanding principal and interest less associated debt
issue costs owed to LEH under the LEH Loan Agreement are reflected
in long-term debt, related party, current portion and long-term
debt, related party, net of current portion in our consolidated
balance sheets.
Ingleside Note
. See “Note (8) Related Party
Transactions” for a summary of the Ingleside
Note.
Notre Dame Debt
. LE entered a loan with Notre Dame
Investors, Inc. as evidenced by a promissory note in the original
principal amount of $8.0 million, which is currently held by John
Kissick (the “Notre Dame Debt”). The Notre Dame Debt
matures in January 2018, and accrues interest at a rate of
16.00%.
The
Notre Dame Debt is secured by a Deed of Trust, Security Agreement
and Financing Statements (the “Subordinated Deed of
Trust”), which encumbers the Nixon Facility and general
assets of LE. There are no financial maintenance
covenants associated with the Notre Dame Debt. Pursuant to a
Subordination Agreement dated June 2015, the holder of the Notre
Dame Debt agreed to subordinate any security interest and liens on
the Nixon Facility, as well as its right to payments, in favor of
Sovereign as holder of the First Term Loan Due 2034.
Carroll Note
. See “Note (8) Related Party
Transactions” for a summary of the Carroll Note.
Term Loan Due 2017
. LRM entered a Loan and Security
Agreement with Sovereign in 2014, for a term loan facility in the
principal amount of $2.0 million (the “Term Loan Due
2017”). The Term Loan Due 2017 was amended in March 2015,
pursuant to a Loan Modification Agreement (the “March Loan
Modification Agreement”). Under the March Loan Modification
Agreement, the interest rate was modified to be the greater of the
Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due
date was extended to March 2017. Pursuant to the March Loan
Modification Agreement, the Term Loan Due 2017 has a current
monthly principal payment of $61,665 plus interest. Due to its
maturity date, the Term Loan Due 2017 was classified within the
current portion of long-term debt on our consolidated balance sheet
at December 31, 2016.
76
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
At
December 31, 2016, LRM was in violation of the debt service
coverage ratio financial covenant related to the Term Loan Due
2017. Consequently, Sovereign could declare the amounts owed under
the Term Loan Due 2017 immediately due and payable, exercise its
rights with respect to collateral securing LRM’s obligations
under the loan agreement, and/or exercise any other rights and
remedies available. The Term Loan Due 2017 was already classified
within the current portion of long-term debt on our consolidated
balance sheets due to the loan’s short-term maturity date.
Sovereign waived the financial covenant default as of the year
ended December 31, 2016. There can be no assurance that Sovereign
will provide future waivers, which may have an adverse impact on
our financial position and results of operations. (See “Note
(1) Organization – Operating Risks-Going Concern” and
“Note (21) Subsequent Events” for additional
disclosures related to the Second Term Loan Due 2034 and financial
covenant violations.)
As a
condition of the Term Loan Due 2017, Jonathan Carroll was required
to guarantee r
epayment
of funds borrowed and
interest accrued under the loan. For his personal guarantee, LRM
entered a Guaranty Fee Agreement with Jonathan Carroll whereby he
receives a fee equal to 2.00% per annum, paid monthly, of the
outstanding principal balance owed under the Term Loan Due 2017.
For the years ended December 31, 2016
and 2015, guaranty fees related to the Term Loan Due 2017 totaled
$10,483 and $11,439, respectively. Guaranty fees are recognized
monthly as incurred and are included in interest and other expense
in our consolidated statements of operations.
The
proceeds of the Term Loan Due 2017 were used primarily to finance
costs associated with refurbishment of the Nixon Facility’s
naphtha stabilizer and depropanizer units. The Term Loan Due 2017
is: (i) subject to a financial maintenance covenant pertaining to
debt service coverage ratio and (ii) secured by the assignment of
certain leases of LRM and certain assets of LEH. (See “Note
(8) Related Party Transactions” for additional disclosures
related to LEH and Jonathan Carroll.)
Capital Leases
. LRM entered a 36-month build-to-suit capital
lease in August 2014 for the purchase of new boiler equipment for
the Nixon Facility. The equipment, which was delivered in December
2014, was added to construction in progress. Once placed in
service, the equipment will be reclassified to refinery and
facilities and depreciation will begin. The capital lease, which
requires a quarterly payment in the amount of $44,258, is
guaranteed by Blue Dolphin.
A
summary of equipment held under long-term capital leases as of the
dates indicated follows:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Boiler
equipment
|
$
538,598
|
$
538,598
|
|
Less:
accumulated depreciation
|
-
|
-
|
|
|
$
538,598
|
$
538,598
|
At
December 31, 2016, future minimum lease commitments under
non-cancelable capital leases were as follow:
|
2017
|
$
138,310
|
|
Less:
amount representing interest
|
(2,431
)
|
|
Present
value of minimum lease payments
|
$
135,879
|
At
December 31, 2016, the present value of minimum lease payments due
within one year was $135,879.
77
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(11)
|
Asset Retirement Obligations
|
Refinery and Facilities
. Management has concluded that there
is no legal or contractual obligation to dismantle or remove the
refinery and facilities assets. Management believes that the
refinery and facilities assets have indeterminate lives under FASB
ASC guidance for estimating AROs because dates or ranges of dates
upon which we would retire these assets cannot reasonably be
estimated at this time. When a legal or contractual obligation to
dismantle or remove the refinery and facilities assets arises and a
date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
Pipelines and Facilities and Oil and Gas Properties
. We have
AROs associated with the dismantlement and abandonment in place of
our pipelines and facilities assets, as well as the plugging and
abandonment of our oil and gas properties. We recorded a discounted
liability for the fair value of an ARO with a corresponding
increase to the carrying value of the related long-lived asset at
the time the asset was installed or placed in service. We
depreciate the amount added to property and equipment and recognize
accretion expense in connection with the discounted liability over
the remaining life of the asset. Plugging and abandonment costs are
recorded during the period incurred or as information becomes
available to substantiate actual and/or probable
costs.
Changes
to our ARO liability for the periods indicated were as
follows:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Asset
retirement obligations, at the beginning of the period
|
$
1,985,864
|
$
1,866,770
|
|
New
asset retirement obligations and adjustments
|
-
|
49
|
|
Liabilities
settled
|
(70,969
)
|
(92,330
)
|
|
Accretion
expense
|
112,744
|
211,375
|
|
|
2,027,639
|
1,985,864
|
|
Less:
asset retirement obligations, current portion
|
(17,510
)
|
(38,644
)
|
|
|
|
|
|
Long-term
asset retirement obligations, at the end of the period
|
$
2,010,129
|
$
1,947,220
|
Liabilities
settled represents amounts paid for plugging and abandonment costs
against the asset’s ARO liability and are reflected in our
consolidated balance sheets. At December 31, 2016 and 2015, we
recognized $70,969 and $92,330, respectively, in liabilities
settled. Abandonment expense represents amounts paid for plugging
and abandonment costs that exceed the asset’s ARO liability
and are reflected in our consolidated statements of operations. For
the years ended December 31, 2016 and 2015, we recognized $0 in
abandonment expense.
|
(12)
|
Impairment
|
For the
years ended December 31, 2016 and 2015, we recorded impairment
expense of $968,684 and $0, respectively. The impairment expense
for the year ended December 31, 2016 related to our pipeline fixed
assets. 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.
|
(13)
|
Treasury Stock
|
At
December 31, 2016 and 2015, we had 150,000 shares of treasury
stock.
78
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(14)
|
Concentration of Risk
|
Bank Accounts
. Financial instruments that potentially
subject us to concentrations of risk consist primarily of cash,
trade receivables and payables. We maintain our cash balances at
financial institutions located in Houston, Texas. In the U.S., the
Federal Deposit Insurance Corporation (the “FDIC”)
insures certain financial products up to a maximum of $250,000 per
depositor. At December 31, 2016 and 2015, we had cash balances more
than the FDIC insurance limit per depositor in the amount of
$5,372,689 and $19,594,883, respectively.
Key Supplier
.
Historically,
we purchased light crude oil and condensate for the Nixon Facility
from GEL pursuant to a Crude Oil Supply and Throughput Services
Agreement (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 nonrenewal
at least 180 days prior to expiration of any renewal term. The
parties are currently involved in a contract-related dispute.
Therefore, 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 I, Item 1A. Risk
Factors” as well as “Note (20) Commitments and
Contingencies – Genesis Agreements” and “Legal
Matters” for disclosures related to the Crude Supply
Agreement and the current contract-related dispute with
GEL.)
In June
2016, we entered a month-to-month evergreen crude supply contract
with a major integrated oil and gas company as back-up to the Crude
Supply Agreement with GEL. 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.
Significant Customers
. We routinely assess the financial
strength of our customers and have not experienced significant
write-downs in our accounts receivable balances. Therefore, we
believe that our accounts receivable credit risk exposure is
limited.
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,
2015, we had 3 customers that accounted for approximately 56% of
our refined petroleum products sales. At December 31, 2015, these 3
customers represented approximately $3.0 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 “Note (8) Related Party Transactions” for
additional disclosures with respect to related
parties.)
Remainder
of Page Intentionally Left Blank
79
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Refined Petroleum Product Sales
. Our refined petroleum
products are primarily sold in the U.S. However, with the opening
of the Mexican diesel market to private companies, we began
exporting low-sulfur diesel to Mexico during the second quarter of
2016. Total refined petroleum product sales by distillation (from
light to heavy) for the periods indicated consisted of the
following:
|
|
Years
Ended December 31,
|
|||
|
|
2016
|
2015
|
||
|
|
|
|
|
|
|
LPG
mix
|
$
714,285
|
0.4
%
|
$
1,253,826
|
0.6
%
|
|
Naphtha
|
35,544,394
|
21.5
%
|
48,410,300
|
22.0
%
|
|
Jet
fuel
|
55,459,227
|
33.5
%
|
67,085,046
|
30.4
%
|
|
HOBM
|
35,924,098
|
21.8
%
|
46,936,751
|
21.3
%
|
|
Reduced
Crude
|
3,791,919
|
2.3
%
|
3,838,273
|
1.7
%
|
|
AGO
|
33,979,855
|
20.5
%
|
52,914,392
|
24.0
%
|
|
|
|
|
|
|
|
|
$
165,413,778
|
100.0
%
|
$
220,438,588
|
100.0
%
|
|
(15)
|
Leases
|
Our
company headquarters is in downtown Houston, Texas. We lease 13,878
square feet of office space, 7,389 square feet of which is used and
paid for by LEH. The office lease has a 10-year term that expires
in September 2017. The lease included a free rent period, has
escalating rent payment provisions, and requires payment of a
portion of operating expenses. Rent expense is recognized on a
straight-line basis. For the years ended December 31, 2016 and
2015, rent expense totaled
$142,604
and $142,604,
respectively.
At
December 31, 2016, future minimum lease commitments that were
non-cancelable under our office lease were as follow:
|
Years
Ending December 31,
|
|
|
2017
|
$
128,852
|
|
(16)
|
Income Taxes
|
Income Tax Benefit (Expense)
. Income tax benefit (expense)
for the periods indicated consisted of the following:
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
Current:
|
|
|
|
Federal
|
$
-
|
$
(111,566
)
|
|
State
|
-
|
(169,867
)
|
|
Deferred:
|
|
|
|
Federal
|
(3,607,237
)
|
(2,152,869
)
|
|
State
|
-
|
-
|
|
|
$
(3,607,237
)
|
$
(2,434,302
)
|
The
state of Texas has a Texas margins tax (“TMT”), which
is a form of business tax imposed on gross margin. Although TMT is
imposed on an entity’s gross profit rather than on its net
income, certain aspects of TMT make it like an income tax.
Accordingly, TMT is treated as an income tax for financial
reporting purposes.
80
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Effective Tax Rate
. Our effective tax rate in 2016 and 2015
was as follows:
|
|
2016
|
2015
|
|
|
|
|
|
Expected
tax rate
|
34.00
%
|
34.00
%
|
|
Permanent
differences
|
0.00
%
|
0.00
%
|
|
State
tax
|
0.00
%
|
1.64
%
|
|
Federal
tax
|
0.00
%
|
0.01
%
|
|
Change
in valuation allowance
|
(63.66
%)
|
0.00
%
|
|
|
(29.66
%)
|
35.65
%
|
Deferred Income Taxes
. Deferred income tax balances reflect
the effects of temporary differences between the carrying amounts
of assets and liabilities and their tax basis, as well as from NOL
carryforwards. We state those balances at the enacted tax rates we
expect will be in effect when taxes are paid. NOL carryforwards and
deferred tax assets represent amounts available to reduce future
taxable income.
NOL Carryforwards
. Under Section 382 of the Internal Revenue
Code of 1986, as amended (“IRC Section 382”), a
corporation that undergoes an “ownership change” is
subject to limitations on its use of pre-change NOL carryforwards
to offset future taxable income. Within the meaning of IRC Section
382, an “ownership change” occurs when the aggregate
stock ownership of certain stockholders (generally 5% shareholders,
applying certain look-through rules) increases by more than 50
percentage points over such stockholders' lowest percentage
ownership during the testing period (generally three years). For
income tax purposes, we experienced ownership changes in 2005, in
connection with a series of private placements, and in 2012, as a
result of a reverse acquisition, that limit the use of pre-change
NOL carryforwards to offset future taxable income. In general, the
annual use limitation equals the aggregate value of common stock at
the time of the ownership change multiplied by a specified
tax-exempt interest rate. The 2012 ownership change will subject
approximately $18.8 million in NOL carryforwards that were
generated prior to the ownership change to an annual use limitation
of $638,196 per year. Unused portions of the annual use limitation
amount may be used in subsequent years. As a result of the annual
use limitation, approximately $6.7 million in NOL carryforwards
that were generated prior to the 2012 ownership change will expire
unused. NOL carryforwards that were generated after the 2012
ownership change are not subject to an annual use limitation under
IRC Section 382 and may be used for a period of 20 years in
addition to available amounts of NOL carryforwards generated prior
to the ownership change.
NOL
carryforwards that remained available for future use for the
periods indicated were as follow (amounts shown are net of NOLs
that will expire unused because of the IRC Section 382
limitation):
|
|
Net Operating Loss Carryforward
|
|
|
|
|
Pre-Ownership Change
|
Post-Ownership Change
|
Total
|
|
|
|
|
|
|
Balance
at December 31, 2014
|
$
10,766,912
|
$
12,145,789
|
$
22,912,701
|
|
|
|
|
|
|
Net
operating loss carryforwards utilized
|
(1,152,463
)
|
(2,528,848
)
|
(3,681,311
)
|
|
|
|
|
-
|
|
Balance
at December 31, 2015
|
9,614,449
|
9,616,941
|
19,231,390
|
|
|
|
|
|
|
Net
operating losses
|
-
|
13,945,128
|
13,945,128
|
|
|
|
|
|
|
Balance
at December 31, 2016
|
$
9,614,449
|
$
23,562,069
|
$
33,176,518
|
81
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Deferred Tax Assets and Liabilities
. At December 31, 2016
and 2015, we had $0 and approximately $3.6 million, respectively,
of net deferred tax assets available for future use. Significant
components of deferred tax assets and liabilities as of the dates
indicated were as follow:
|
|
December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Deferred
tax assets:
|
|
|
|
Net
operating loss and capital loss carryforwards
|
$
13,550,338
|
$
8,815,794
|
|
Start-up
costs (Nixon Facility)
|
1,373,363
|
1,510,699
|
|
Asset
retirement obligations liability/deferred revenue
|
717,751
|
717,723
|
|
Unrealized
hedges
|
-
|
62,356
|
|
AMT
credit and other
|
266,522
|
302,086
|
|
Total
deferred tax assets
|
15,907,974
|
11,408,658
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
Fair
market value adjustments
|
-
|
(46,116
)
|
|
Unrealized
hedges
|
-
|
-
|
|
Basis
differences in property and equipment
|
(5,895,943
)
|
(5,484,983
)
|
|
Total
deferred tax liabilities
|
(5,895,943
)
|
(5,531,099
)
|
|
|
|
|
|
|
10,012,031
|
5,877,559
|
|
|
|
|
|
Valuation
allowance
|
(10,012,031
)
|
(2,270,322
)
|
|
|
|
|
|
Deferred
tax assets, net
|
$
-
|
$
3,607,237
|
Valuation Allowance
. As of each reporting date, management
considers new evidence, both positive and negative, that could
impact management’s view regarding future realization of
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.
Current Versus Long-Term
. Effective April 1, 2016, we
adopted the provisions of the FASB ASC guidance that 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. 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.
Uncertain Tax Positions
. We adopted the provisions of the
FASB ASC guidance on accounting for uncertainty in income taxes.
The guidance clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements. The
guidance also prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement
of a tax position taken or expected to be taken in a tax return.
The standard also provides guidance on de-recognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition.
As part
of this guidance, we record income tax related interest and
penalties, if applicable, as a component of the provision for
income tax benefit (expense). However, there were no amounts
recognized relating to interest and penalties in the consolidated
statements of operations for the years ended December 31, 2016 and
2015. Our federal income tax returns are subject to examination by
the Internal Revenue Service for tax years ending December 31,
2013, or after and by the state of Texas for tax years ending
December 31, 2012, or after. We believe there are no uncertain tax
positions for both federal and state income taxes.
82
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
|
(17)
|
Earnings Per Share
|
A
reconciliation between basic and diluted income per share for the
periods indicated was as follows:
|
|
Years
Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Net
income (loss)
|
$
(15,767,448
)
|
$
4,403,239
|
|
|
|
|
|
Basic
and diluted income per share
|
$
(1.51
)
|
$
0.42
|
|
|
|
|
|
Basic and Diluted
|
|
|
|
Weighted
average number of shares of
|
|
|
|
common
stock outstanding and potential
|
|
|
|
dilutive
shares of common stock
|
10,464,061
|
10,451,832
|
Diluted
EPS is computed by dividing net income available to common
stockholders by the weighted average number of shares of common
stock outstanding. Diluted EPS for the years ended December 31,
2016 and 2015 was the same as basic EPS as there were no stock
options or other dilutive instruments outstanding.
|
(18)
|
Fair Value Measurement
|
We may
purchase and execute the sale of financial instruments to
economically hedging commodity price risks associated with our
refined petroleum products and the purchase of crude oil and
condensate. We account for derivatives in our financial records by
utilizing the market approach when measuring fair value of our
financial instruments (typically in current assets and/or
liabilities, as discussed below). The market approach uses prices
and other relevant information generated by such market
transactions involving identical or comparable assets or
liabilities.
Generally
accepted accounting principles establish a framework for measuring
fair value. That framework provides a fair value hierarchy that
prioritizes the inputs to valuation techniques used to measure fair
value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities
(Level 1 measurements) and the lowest priority to unobservable
inputs (Level 3 measurements). The fair value hierarchy consists of
the following three levels:
|
Level
1
|
Inputs
are quoted prices (unadjusted) in active markets for identical
assets or liabilities.
|
|
|
|
|
Level
2
|
Inputs
are quoted prices for similar assets or liabilities in an active
market, quoted prices for identical or similar assets or
liabilities in markets that are not active, inputs other than
quoted prices that are observable and market-corroborated inputs,
which are derived principally from or corroborated by observable
market data.
|
|
|
|
|
Level
3
|
Inputs
are derived from valuation techniques in which one or more
significant inputs or value drivers are unobservable and cannot be
corroborated by market data or other entity-specific
inputs.
|
The
carrying amounts of accounts receivable, accounts payable, and
accrued liabilities approximated their fair values at December 31,
2016 and 2015 due to their short-term maturities. The fair value of
our long-term debt, net (including both the current and non-current
portions of long-term debt and related party) at December 31, 2016
and 2015 was $40,590,023 and $37,172,668, respectively. The fair
value of our debt was determined using a Level 3
hierarchy.
83
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
The
following table represents our assets and liabilities measured at
fair value on a recurring basis at December 31, 2016 and 2015 and
the basis for the measurement:
|
|
|
Fair Value Measurement at December 31, 2016 Using
|
||
|
Financial assets (liabilities):
|
Carrying Value at December 31, 2016
|
Quoted Prices in Active Markets for Identical Assets or Liabilities
(Level 1)
|
Significant Other Observable Inputs
(Level 2)
|
Significant Unobservable Inputs
(Level 3)
|
|
|
|
|
|
|
|
Commodity
contracts
|
$
-
|
$
-
|
$
-
|
$
-
|
|
|
Fair Value Measurement at
December 31, 2015 Using
|
|||
|
Financial assets
(liabilities):
|
Carrying Value at December
31, 2015
|
Quoted Prices in Active
Markets for Identical Assets or Liabilities
(Level 1)
|
Significant Other Observable
Inputs
(Level 2)
|
Significant Unobservable
Inputs
(Level 3)
|
|
|
|
|
|
|
|
Commodity
contracts
|
$
(183,400
)
|
$
(183,400
)
|
$
-
|
$
-
|
Carrying
amounts of commodity contracts are reflected as other current
assets or other current liabilities in our consolidated balance
sheets.
|
(19)
|
Inventory Risk Management
|
Management
periodically determines whether to maintain, increase, or decrease
inventory levels based on various factors, including the crude
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.
Under our inventory risk management policy, commodity futures
contracts may be used to mitigate the change in value for certain
of our refined petroleum product inventories subject to market
price fluctuations in our inventory. The physical inventory volumes
are not exchanged, and these contracts are net settled with
cash.
The
fair value of commodity futures contracts is reflected in our
consolidated balance sheets and the related net gain or loss is
recorded within cost of refined products sold in our consolidated
statements of operations. Quoted prices for identical assets or
liabilities in active markets (Level 1) are considered to determine
the fair values for marking to market the financial instruments at
each period end.
Commodity
transactions are executed to minimize transaction costs, monitor
consolidated net exposures, and allow for increased responsiveness
to changes in market factors. Due to mark-to-market accounting
during the term of the commodity futures contracts, significant
unrealized non-cash net gains and losses could be recorded in our
results of operations.
At
December 31, 2016, we had the following obligations based on
futures contracts of refined petroleum products and crude oil and
condensate that were entered as economic hedges. The information
presents the notional volume of open commodity instruments by type
and year of maturity (volumes in bbls):
|
|
Notional
Contract Volumes by Year of Maturity
|
||
|
Inventory positions (futures):
|
2016
|
2017
|
2018
|
|
|
|
|
|
|
Refined
petroleum products and crude oil -
|
|
|
|
|
net
short positions
|
-
|
-
|
-
|
84
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
The
following table provides the location and fair value amounts of
derivative instruments that are reported in our consolidated
balance sheets at December 31, 2016 and 2015:
|
|
|
|
|
Fair Value
|
||
|
|
|
|
|
December 31,
|
||
|
Asset Derivatives
|
|
Balance Sheets Location
|
|
2016
|
|
2015
|
|
|
|
Prepaid expenses and other current
|
|
|
|
|
|
|
|
assets (accrued expenses and other
|
|
|
|
|
|
Commodity contracts
|
|
current liabilities)
|
|
$-
|
|
$(183,400)
|
The
following table provides the effect of derivative instruments in
our consolidated statements of operations for the years ended
December 31, 2016 and 2015:
|
|
|
|
Gain
(Loss) Recognized
|
|
|
|
|
|
Years
Ended December 31,
|
|
|
Derivatives
|
|
Statements of Operations Location
|
2016
|
2015
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Cost
of refined products sold
|
$
(2,445,898
)
|
$
3,730,613
|
|
(20)
|
Commitments and Contingencies
|
Operating Agreement
. (See “Note (8) Related Party
Transactions” for additional disclosures related to the
Operating Agreement.)
Genesis Agreements
. We are party to the following agreements
with Genesis:
Crude Supply Agreement
. Historically, GEL supplied the Nixon
Facility with crude oil and condensate under the Crude Supply
Agreement at cost plus freight expense and any costs associated
with hedging. All crude oil and condensate supplied under the Crude
Supply Agreement was paid for pursuant to the terms of the Joint
Marketing Agreement as described within this section.
Joint Marketing Agreement
. Under the Joint Marketing
Agreement, we, together with GEL, jointly marketed and sold certain
output produced at the Nixon Facility and shared the associated
Gross Profits (as defined below) from such sales. Payments for the
sale of certain output produced at the Nixon Facility were made
directly to GEL as collection agent, and associated customers had
to satisfy GEL’s customer credit approval process. The Joint
Marketing Agreement provided for the sharing of “Gross
Profits” (defined as the total revenue from the sale of
certain output from the Nixon Facility minus the cost of crude oil
and condensate pursuant to the Crude Supply Agreement). Key
provisions of the Joint Marketing Agreement were as
follows:
●
We were entitled to
receive weekly operations payments to cover direct expenses in
operating the Nixon Facility in an amount not to exceed $750,000
per month. In addition, we were entitled to receive reimbursement
for accounting fees, if incurred, not to exceed $50,000 per month.
We assigned our rights to the operations payments and reimbursement
of accounting fees under the Joint Marketing Agreement to LEH
pursuant to the Operating Agreement; and
●
GEL was entitled to
receive an administrative fee in the amount of $150,000 per month
relating to the performance of its obligations under the Joint
Marketing Agreement (the “Performance Fee”). GEL was
entitled to receive 30% of the remaining Gross Profit up to
$600,000 (the “Threshold Amount”) as the GEL Profit
Share, and we were entitled to receive 70% of the remaining Gross
Profit as our Profit Share. Any amount of remaining Gross Profit
that exceeded the Threshold Amount for a calendar month was payable
to GEL and us in the following manner: (i) GEL was entitled to
receive 20% of the remaining Gross Profits over the Threshold
Amount as the GEL Profit Share and (ii) we were entitled to receive
80% of the remaining Gross Profits over the Threshold Amount as our
Profit Share. The GEL Profit Share plus the Performance Fee are
collectively referred to herein as the “Joint Marketing
Agreement Profit Share” or the “JMA Profit
Share”.
85
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
The
Crude Supply Agreement and Joint Marketing Agreement automatically
renew for successive one-year terms until August 2019 unless GEL
provides us with notice of nonrenewal at least 180 days prior to
expiration of any renewal term. The parties are currently involved
in a contract-related dispute. Consequently, we ceased purchases of
crude oil and condensate from GEL in November 2016. Following the
marketing and sale of all refined petroleum products processed
through the Nixon Facility using GEL supplied crude oil and
condensate, we suspended use of GEL’s services under the
Joint Marketing Agreement.
Pursuant
to a Letter Agreement Regarding Subordination of GEL Transaction
Documents dated in June 2015, we, among other things, assigned our
rights to payments under the Crude Supply Agreement and Joint
Marketing Agreement as collateral in favor of Sovereign Bank, as
lender and lienholder pursuant to the First Term Loan Due 2034.
(See “Note (10) Long-Term Debt, Net” for further
discussion related to the First Term Loan Due 2034.)
GEL Contract-Related Dispute
. LE currently has a
contract-related dispute with GEL related to the Joint Marketing
Agreement and Crude Supply Agreement. (See “Legal
Matters” below for a discussion of the current
contract-related dispute with GEL.)
FLNG Easement Agreements
. BDPL and FLNG were parties to a
Pipeline Easement dated November 5, 2005 (the “FLNG Pipeline
Easement”) and the FLNG Master Easement Agreement (together
with the FLNG Pipeline Easement, the “FLNG Easements”).
The FLNG Easements provided FLNG and its affiliates: (i) a pipeline
easement and right of way across the BDPL Property to certain
property owned by FLNG and (ii) rights of ingress and egress across
the BDPL Property to the property owned by FLNG. Under the FLNG
Easements, FLNG made payments to us in the amount of $500,000 each
year. The FLNG Easements were terminated in February 2017. See
“Part II, Item 8. Financial Statements and Supplementary Data
– Note (21) Subsequent Events” for additional
disclosures related to the FLNG Easements.
Supplemental Pipeline Bonds
. In August 2015, we received a
letter from the Bureau of Ocean Energy Management (the
“BOEM”) requiring additional supplemental bonds or
acceptable financial assurance of approximately $4.2 million for
existing pipeline rights-of-way. In July 2016, the BOEM issued
Notice to Lessees (“NTL”) No. 2016-N01 (Requiring
Additional Security), which changes the way that lessees and
rights-of-way holders demonstrate financial strength and
reliability to plug and abandon wells, as well as decommission and
remove platforms and pipelines at the end of production or service
activities. The NTL, which changed an earlier supplemental waiver
process to a self-insurance model, became effective in September
2016. Pursuant to the NTL, the BOEM requested that lessees submit
any relevant information needed for an overall financial review of
the lessees account. The BOEM indicated that it would use this
information to evaluate a lessees’ ability to carry out its
obligations and determine whether, and/or how much self-insurance a
lessee can use.
In
October 2016, we received a letter from 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 pipeline bonds or acceptable financial
reassurance 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-ways 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.
Financing Agreements
. (See “Note (10) Long-Term Debt,
Net” for additional disclosures related to financing
agreements.)
86
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
Grynberg Settlement Agreement
. In October 2015, we entered a
final
Mutual Release Agreement and
Withdrawal of All Qui Tam Claims
(the “Grynberg
Settlement Agreement”). The Grynberg Settlement Agreement
provided for a settlement in the amount of $725,073 (the
“Settlement Amount”). The Settlement Amount represented
50% of a $1,371,723 November 2006 summary judgment in our favor
plus 1.5% interest. We received the cash Settlement Amount in
October 2015. For the year ended December 31, 2015, we recognized a
net gain of $660,000 in other income from the Grynberg Matter (the
Settlement Amount less additional legal fees of approximately
$65,000). The Grynberg matter was a nearly two decades-old case
involving Jack J. Grynberg and several defendants in the oil and
gas industry, including BDPL.
Nixon Facility Expansion
. W
e
have made and continue to make
capital and efficiency improvements to the Nixon Facility.
Therefore, we incurred and will continue to incur capital
expenditures related to these improvements, which include, among
other things, facility and land improvements and construction of
additional petroleum storage tanks.
Legal Matters
.
GEL Contract-Related Dispute.
As described above under
“Genesis Agreements,” 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, in
connection with 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 a
Dispute Resolution Agreement between the parties (the
“Arbitration”). The Arbitration alleges that GEL
breached the Crude Supply Agreement by:
(i)
overcharging for
crude oil and condensate based on Genesis’ cost as defined in
the Crude Supply Agreement,
(ii)
overcharging for
trucking costs, and
(iii)
significantly
under-delivering crude oil and condensate, resulting in 59 days of
refinery downtime and significant decreases in refinery throughput,
refinery production, and refined petroleum product sales for the
year ended December 31, 2016.
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
Genesis and 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.
87
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Notes
to Consolidated Financial Statements
(Continued)
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.
Health, Safety and Environmental Matters
. All our operations
and properties are subject to extensive federal, state, and local
environmental, health, and safety regulations governing, among
other things, the generation, storage, handling, use and
transportation of petroleum and hazardous substances; the emission
and discharge of materials into the environment; waste management;
characteristics and composition of jet fuel and other products; and
the monitoring, reporting and control of greenhouse gas emissions.
Our operations also require numerous permits and authorizations
under various environmental, health, and safety laws and
regulations. Failure to obtain and comply with these permits or
environmental, health, or safety laws generally could result in
fines, penalties or other sanctions, or a revocation of our
permits.
|
(21)
|
Subsequent Events
|
Financial Covenant Defaults
.
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.
By
letter dated March 29, 2017, 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.
Termination of FLNG Easements, Acceleration of Payment Obligations,
Land Sale
.
In
February 2017, BDPL completed several related transactions with
Freeport LNG Expansion, L.P. ("FLEX") and FLNG. BDPL sold
approximately 15 acres of the BDPL Property to FLIQ Common
Facilities, LLC, an affiliate of FLEX, for cash proceeds of
approximately $539,000. In connection with the sale of real estate,
FLNG paid to BDPL approximately $1,336,000 as consideration for the
full satisfaction and discharge of FLNG's future annual payment and
other obligations to BDPL under the FLNG Easements.
In
connection with entry into the FLNG Master Easement Agreement, BDPL
and FLEX entered a Letter of Intent dated December 11, 2013 (the
"Letter of Intent"), pursuant to which BDPL and FLEX committed to
study the feasibility of jointly developing facilities to source
and supply liquefied natural gas for sale to third parties for use
as transportation fuel in the U.S. domestic transportation
markets. In connection with the sale of real estate, BDPL and
FLEX terminated the Letter of Intent. No definitive
agreements for any transaction contemplated by the Letter of Intent
were entered between the parties prior to the termination of the
Letter of Intent.
Remainder
of Page Intentionally Left Blank
88
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
None.
Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other
procedures that are designed to ensure that information required to
be disclosed by us in the reports we file or submit under the
Securities Exchange Act of 1934, as amended (the “Exchange
Act”) is recorded, processed, summarized and reported within
the time periods specified by SEC rules and forms. Disclosure
controls and procedures include, without limitation, controls and
procedures designed to ensure that information required to be
disclosed by us in the reports we file or submit under the Exchange
Act is accumulated and communicated to management, including the
Chief Executive Officer (principal executive officer) and the Chief
Financial Officer (principal financial officer), as appropriate to
allow timely decisions regarding required disclosure. Under the
supervision of, and with the participation of our management,
including our Chief Executive Officer (principal executive officer)
and Chief Financial Officer (principal financial officer), we
conducted an evaluation of the effectiveness of our disclosure
controls and procedures, as defined in Rules 13a-15(e) and
15d-15(e) under the Exchange Act, as of the end of the period
covered by this Annual Report. Based on our evaluation, our Chief
Executive Officer (principal executive officer) and Chief Financial
Officer (principal financial officer) concluded that our disclosure
controls and procedures were effective as of the end of the period
covered by this report to ensure that information required to be
disclosed by us in reports that we file or submit under the
Exchange Act, are recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and
forms.
Management’s Report on Internal Control over Financial
Reporting
Management’s Responsibility
.
Management is responsible for establishing and
maintaining adequate internal control over financial reporting, as
such term is defined in Rules 13a-15(f) and 15d-15(f) under the
Exchange Act. A company’s internal control over financial
reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in
accordance with generally accepted accounting principles in the
United States.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management’s Assessment
.
Management, under the supervision and with the
participation of our Chief Executive Officer (principal executive
officer) and Chief Financial Officer (principal financial officer),
assessed the effectiveness of our internal controls over financial
reporting at December 31, 2016. In making this assessment,
management used the criteria set forth by the 2013 Committee of
Sponsoring Organizations of the Treadway Commission Framework and
SOX Compliance. In connection with such evaluation, management
concluded that our internal controls over financial reporting were
effective at December 31, 2016.
Changes in Internal Control over Financial
Reporting
. During the period
covered by this report there have been no changes in our internal
control over financial reporting that materially affected, or is
reasonably likely to materially affect, our internal control over
financial reporting.
89
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Exemption from Management's Report on Internal Control over
Financial Reporting
. This
Annual Report does not include an attestation report of our
registered public accounting firm regarding internal control over
financial reporting. Management’s report was not subject to
attestation by our registered public accounting firm pursuant to
rules of the SEC that permit us to provide only management’s
attestation in this Annual Report.
None.
Remainder
of Page Intentionally Left Blank
90
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Structure and Management
We are
currently controlled by Lazarus Energy Holdings, LLC
(“LEH”), which owns approximately 81% of our Common
Stock. LEH manages and operates all our properties pursuant to an
Operating Agreement. Jonathan P. Carroll is Chairman of the Board,
Chief Executive Officer and President of Blue Dolphin, as well as a
majority owner of LEH. Under the Operating Agreement, LEH provides
us with personnel, among other services, in capacities equivalent
to Chief Executive Officer and Chief Financial
Officer.
Board Composition
The
amended and restated bylaws of Blue Dolphin provide that the Board
shall consist of five members, with the precise number to be
determined from time to time by the Board, except that no decrease
in the number shall have the effect of shortening the term of an
incumbent director. The Board currently has five directors, each
serving until the next annual meeting of stockholders to be held by
Blue Dolphin.
The
following sets forth, at March 31, 2017, each director’s
name, age, principal occupation and directorships during the past
five (5) years, as well as their relevant knowledge and experience
that led to their appointment to the Board:
|
Name, Age
Principal Occupation and Directorships During Past 5
Years
|
|
Knowledge and Experience
|
|
|
|
|
|
Jonathan P. Carroll
, 55
Blue
Dolphin Energy Company
Chairman of the Board
(since 2014)
Chief Executive Officer, President,
Assistant Treasurer and Secretary
(since 2012)
Lazarus
Energy Holdings, LLC (“LEH”)
Majority Owner and President
(since 2006)
LEH
owns approximately 81% of our outstanding Common
Stock.
Mr.
Carroll has served on Blue Dolphin’s Board since
2014. He is currently Chairman of the
Board. Since 2004, he has served on the Board of
Trustees of the Salient Fund Group, and has served on the
compliance, audit and nominating committees of several of
Salient’s private and public closed-end and mutual
funds. Mr. Carroll previously served on the Board of
Directors of the General Partner of LRR Energy, L.P. (NYSE: LRE)
from January 2014 until its merger with Vanguard Natural
Resources, LLC in October 2015.
|
|
Mr.
Carroll earned a Bachelor of Arts degree in Human Biology and a
Bachelor of Arts degree in Economics from Stanford University, and
he completed a Directed Reading in Economics at Oxford
University. Based on his educational and professional
experiences, Mr. Carroll possesses particular knowledge and
experience in business management, finance and business development
that strengthen the Board’s collective qualifications, skills
and experience.
|
|
Ryan A. Bailey
, 40
Children’s
Health System of Texas
Head of Investments
(since 2014)
The
Meadows Foundation
Investment Officer/Interim Chief Investment Officer
(2006 to
2014)
Mr.
Bailey was appointed to Blue Dolphin’s Board in November
2015. He is currently a member of the Audit and
Compensation Committees, as well as a member of the Special
Committee on MLP Conversion. He also serves as an
advisor and mentor to Texas Wall Street Women and Chartered
Alternative Investment Analysis Association (Dallas Chapter) --
non-profit member organizations.
|
|
Mr.
Bailey earned a Bachelor of Arts in Economics from Yale University
and completed a graduate course in tax planning from the Yale
School of Management. He holds professional
credentialing as a Chartered Financial Analysist (CFA), Financial
Risk Manager (FRM), Chartered Alternative Investment Analyst (CAIA)
and Chartered Market Technician (CMT). Based on his educational and
professional experiences, Mr. Bailey possesses particular knowledge
and experience in finance, financial analysis and modeling,
investment management, risk assessment and strategic planning that
strengthen the Board’s collective qualifications, skills and
experience.
|
|
|
|
|
91
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
Name, Age
Principal Occupation and Directorships During Past 5
Years
|
|
Knowledge and Experience
|
|
|
|
|
|
Amitav Misra
, 39
Cardinal
Advisors
Founding Partner
(since 2014)
Taxa,
Inc.
President, Director and Chief Operating Officer
(2012 to
2014)
EnerNOC,
Inc.
Channel Manager
(2011 to 2012)
Private
Investment Partnership
Partner
(2007 to 2011)
Mr.
Misra has served on Blue Dolphin’s Board since 2014. He is
currently a member of the Audit and Compensation Committees, as
well as a member of the Special Committee on MLP Conversion. Mr.
Misra serves as an advisor to several energy technology and private
investment companies. He is also a director of the Houston Center
for Literacy, a non-profit.
|
|
Mr.
Misra earned a Bachelor of Arts in Economics from Stanford
University and holds FINRA Series 79 and Series 63 licenses. Mr.
Misra possesses particular knowledge and experience in economics,
business development, private equity, and strategic planning that
strengthen the Board’s collective qualifications, skills and
experience.
|
|
|
|
|
|
Christopher T. Morris
, 55
Tatum
(a Randstad Company)
New York Managing Partner
(since 2013)
MPact
Partners LLC
President
(2011 to 2013)
Freddie
Mac
Vice President (various divisions)
(2000 to
2010)
Mr.
Morris has served on Blue Dolphin’s Board since 2012; he is
currently Chairman of the Audit and Compensation Committees, as
well as Chairman of the Special Committee on MLP
Conversion.
|
|
Mr.
Morris earned a Bachelor of Arts in Economics from Stanford
University and a Masters in Business Administration from the
Harvard Business School. Based on his educational and professional
experiences, Mr. Morris possesses particular knowledge and
experience in business management, finance, strategic planning and
business development that strengthen the Board’s collective
qualifications, skills and experience.
|
|
|
|
|
|
|
|
|
|
Herbert N. Whitney
, 76
Wildcat
Consulting, LLC
Founder and President
(since 2006)
Mr.
Whitney has served on Blue Dolphin’s Board since 2012. He
previously served on the Board of Directors of Blackwater Midstream
Corporation, the Advisory Board of Sheetz, Inc., as Chairman of the
Board of Directors of Colonial Pipeline Company, and as Chairman of
the Executive Committee of the Association of Oil
Pipelines.
|
|
Mr.
Whitney has more than 40 years of experience in pipeline
operations, crude oil supply, product supply, distribution and
trading, as well as marine operations and logistics having served
as the President of CITGO Pipeline Company and in various general
manager positions at CITGO Petroleum Corporation. He earned his
Bachelor of Science in Civil Engineering from Kansas State
University. Based on his educational and professional experiences,
he possesses extensive knowledge in the supply and distribution of
crude oil and petroleum products, which strengthens the
Board’s collective qualifications, skills and
expertise.
|
Remainder
of Page Intentionally Left Blank
92
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Executive Officers
The
following sets forth, at March 31, 2017, the name and age of each
executive officer, as well as their principal occupation during the
past five (5) years:
|
Name
|
|
Position
|
|
Since
|
|
Age
|
|
|
|
|
|
|
|
|
|
Jonathan P. Carroll
|
|
Chief Executive Officer, President, Assistant Treasurer, and
Secretary
|
|
2014
|
|
55
|
|
|
|
|
|
|
|
|
|
Tommy L. Byrd
|
|
Chief Financial Officer
|
|
2015
|
|
59
|
|
|
|
Treasurer and Assistant Secretary
|
|
2012
|
|
|
Jonathan P. Carroll
was appointed Chairman of the Board of
Blue Dolphin in 2014, and he was appointed Chief Executive Officer,
President, Assistant Treasurer and Secretary of Blue Dolphin in
2012. He is also majority owner and President of
LEH. LEH owns approximately 81% of Blue Dolphin’s
Common Stock. Before founding LEH, Mr. Carroll was a
private investor focused on direct debt and equity investments,
primarily in distressed assets.
Mr.
Carroll has served on Blue Dolphin’s Board since 2014. He is
currently Chairman of the Board. Since 2004, he has served on the
Board of Trustees of the Salient Fund Group, and has served on the
compliance, audit and nominating committees of several of
Salient’s private and public closed-end and mutual funds. Mr.
Carroll previously served on the Board of Directors of the General
Partner of LRR Energy, L.P. (NYSE: LRE) from January 2014 until its
merger with Vanguard Natural Resources, LLC in October
2015.
He
earned a Bachelor of Arts degree in Human Biology and a Bachelor of
Arts degree in Economics from Stanford University, and he completed
a Directed Reading in Economics at Oxford University.
Tommy L. Byrd
was appointed Chief Financial Officer of Blue
Dolphin in November 2015 having previously served as Interim Chief
Financial Officer from 2012 through November 2015 and as Controller
from 2011 to 2012. Mr. Byrd also serves as Treasurer and
Assistant Secretary of Blue Dolphin, positions for which he was
appointed in 2012. He earned a Bachelor of Business
Administration in Accounting from Stephen F. Austin State
University. Mr. Byrd has extensive financial management,
accounting and internal audit experience in the energy
industry.
Family Relationships between Directors and Officers
At
March 30, 2017, there were no family relationships between any of
our directors or executive officers.
Committees and Meetings of the Board
Board
The
Board consists of Messrs. Carroll, Bailey, Misra, Morris and
Whitney with Mr. Carroll serving as Chairman. During 2016, the
Board did not meet. The Board has two standing committees, the
Audit Committee and the Compensation Committee. In 2013, the Board
formed a Special Committee of the Board to oversee a potential
conversion of Blue Dolphin from a Delaware “C”
corporation to a Delaware MLP.
Audit Committee
The
Audit Committee consists of Messrs. Morris, Bailey, and Misra with
Mr. Morris serving as Chairman. During 2016, the Audit Committee
met five (5) times. The Board has affirmatively determined that all
members of the Audit Committee are independent and that Messrs.
Morris and Bailey qualify as Audit Committee Financial Experts. The
Audit Committee's duties include overseeing financial reporting and
internal control functions. The Audit Committee’s written
charter is available on our corporate website (
http://www.blue-dolphin-energy.com
).
93
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Compensation Committee
The
Compensation Committee consists of Messrs. Morris, Bailey, and
Misra with Mr. Morris serving as Chairman. During 2016, the
Compensation Committee did not meet. The Board has affirmatively
determined that all members of the Compensation Committee are
independent. The Compensation Committee’s duties include
setting and overseeing our compensation policies, as well as
reviewing and recommending to the Board for its approval all
compensation for the Chief Executive Officer, other senior
executives, and directors. The Compensation Committee’s
written charter is available on our corporate website (
http://www.blue-dolphin-energy.com
).
Master Limited Partnership ("MLP") Conversion Special
Committee
The MLP
Conversion Special Committee consists of Messrs. Morris, Bailey,
and Misra with Mr. Morris serving as Chairman. During 2016, the MLP
Conversion Special Committee did not meet. The Board has
affirmatively determined that all current members of the MLP
Conversion Special Committee are independent. The MLP Conversion
Special Committee was formed by the Board in 2013 to begin a
strategic review of the feasibility of optimizing stockholder value
by converting Blue Dolphin from a publicly traded “C”
corporation to a publicly traded MLP. Due to a shift in market
conditions, the MLP Conversion Special Committee determined in 2016
that a conversion in the foreseeable future would not be in the
best interests of shareholders.
Nominating Committee
Given
the size of the Board, the Board adopted a “Board Nomination
Procedures” policy in lieu of appointing a standing
nominating committee. The policy is used by independent members of
the Board when choosing nominees to stand for election. The Board
will consider for possible nomination qualified nominees
recommended by stockholders. As addressed in the “Board
Nomination Procedures” policy, the way independent directors
evaluate nominees for director as recommended by a stockholder is
the same as that for nominees received from other
sources.
The
Board endeavors to nominate qualified directors that will make
important contributions to the Board and to Blue Dolphin. The Board
generally requires that nominees be persons of sound ethical
character, can represent all stockholders fairly, have demonstrated
professional achievements, have meaningful experience, and have a
general appreciation of the major business issues facing Blue
Dolphin. The Board also considers issues of diversity and
background in its selection process, recognizing that it is
desirable for its membership to have differences in viewpoints,
professional experiences, educational backgrounds, skills, race,
gender, age and national origin.
Corporate Governance
Leadership Structure
Blue
Dolphin is led by Jonathan P. Carroll, who has served as Chairman
of the Board since 2014 and as our Chief Executive Officer and
President since 2012. Having a single leader is commonly utilized
by other public companies in the U.S., and we believe it is
effective for Blue Dolphin as well. This leadership structure
demonstrates to our personnel, customers and stockholders that we
are under strong leadership, with a single person setting the tone
and having primary responsibility for managing our operations, and
eliminates the potential for confusion or duplication of efforts.
We do not believe that appointing an independent Board chairman, or
a permanent lead director, would improve the performance of the
Board.
Risk Oversight
The
Board has responsibility for risk oversight, with reviews of
certain areas being conducted by the relevant committees of the
Board. These committees then provide oral reports to the full
board. The oversight responsibility of the board and its committees
is enabled by management reporting processes that are designed to
provide visibility to the board about the identification,
assessment, and management of critical risks and management’s
risk mitigation strategies. These areas of focus include strategic,
operational, financial and reporting, compliance, and other risks.
The Board and Audit Committee meet in executive session with
representatives of outside advisors as required.
94
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Code of Ethics and Code of Conduct
In
compliance with the Sarbanes-Oxley Act of 2002, the Board adopted a
code of ethics policy in 2003 and a code of conduct policy in 2005.
The Audit Committee established procedures to enable anyone who has
a concern about our conduct, policies, accounting, internal
controls over financial reporting, and/or auditing matters to
communicate that concern directly to the Chairman of the Audit
Committee. The code of ethics and code of conduct policies are
available to any stockholder, without charge, upon written request
to Blue Dolphin Energy Company, Attention: Audit Committee
Chairman, 801 Travis Street, Suite 2100, Houston, Texas 77002. Our
code of ethics and code of conduct policies are available on our
website (
http://www.blue-dolphin-energy.com
).
Any amendments or waivers to provisions of our code of ethics and
code of conduct policies will be incorporated in revised policies
as posted on our website. During 2016, there were no substantive
amendments to our Code of Ethics and Code of Conduct
policies.
Communicating with Directors
Since
the Board does not receive a large volume of correspondence from
stockholders, there is no formal process by which stockholders can
communicate directly with the Board at this time. Instead, any
stockholder who desires to contact the Board or specific members of
the Board may do so by writing to: Blue Dolphin Energy Company,
Attention: Secretary for the Board, 801 Travis Street, Suite 2100,
Houston, Texas 77002. Currently, all communications addressed in
such manner are sent directly to the indicated directors. In the
future, if the Board adopts a formal process for determining how
communications are to be relayed to directors, that process will be
disclosed on Form 8-K as filed with the SEC.
Executive Compensation Policy and Procedures
LEH
manages and operates all our properties pursuant to an Operating
Agreement (the “Operating Agreement”). Under the
Operating Agreement, LEH provides us with personnel, among other
services, in capacities equivalent to Chief Executive Officer and
Chief Financial Officer. All Blue Dolphin personnel work for and
are paid directly by LEH. Blue Dolphin is billed at cost by LEH for
certain personnel associated with Blue Dolphin Pipe Line Company, a
wholly owned subsidiary of Blue Dolphin.
Compensation for Named Executives
Pursuant
to the Operating Agreement, compensation paid to our principal
executive officer, principal financial officer, and the most highly
compensated executive officers other than the principal executive
officer and principal financial officer whose annual salary
exceeded $100,000 in the fiscal year ended December 31, 2016
(collectively, the “Named Executive Officers”) for
services rendered to Blue Dolphin follows:
SUMMARY
COMPENSATION TABLE
|
Name and Principal Position
|
|
Year
|
Salary
|
Option Awards
|
Total
|
|
|
|
|
|
|
|
|
Jonathan
P. Carroll
|
|
|
|
|
|
|
Chief
Executive Officer and President
|
|
2016
|
$
-
|
$
-
|
$
-
|
|
|
|
2015
|
$
-
|
$
-
|
$
-
|
|
|
|
|
|
|
|
|
Tommy L. Byrd
(1)
|
|
|
|
|
|
|
Chief
Financial Officer
|
|
2016
|
$
100,000
|
$
-
|
$
100,000
|
|
|
|
2015
|
$
100,000
|
$
-
|
$
100,000
|
(1) A portion of Mr. Byrd’s compensation is
billed to Blue Dolphin at cost pursuant to the Operating
Agreement.
95
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Compensation Risk Assessment
LEH’s
approach to compensation practices and policies applicable for
executive and non-executive personnel throughout our organization
is consistent with the base pay market median for each position.
LEH believes its practices and policies in this regard are not
reasonably likely to have a materials adverse effect on
us.
Outstanding Equity Awards
None.
Director Compensation Policy and Procedures
Under
the Operating Agreement, LEH provides us with personnel, among
other services, in capacities equivalent to Chief Executive Officer
and Chief Financial Officer. Therefore, we do not have any
directors that are also personnel of Blue Dolphin. The Compensation
Committee reviews and recommends to the Board for its approval all
compensation for the directors.
Compensation for Non-Employee Directors
The
annual retainer payable to non-employee directors serving on the
Board is $40,000 per year. Payments are made in Common Stock and
cash on a quarterly rotating basis.
Cash Fees
. Cash fees reflect the amount of cash compensation
earned for Board and committee service. For service on the Board,
non-employee directors are entitled to receive cash payments in the
amount of $10,000 for services rendered in the second and fourth
quarters of each year.
Additional
compensation is paid to non-employee directors for serving on the
Audit Committee. The chairman of the Audit Committee receives an
additional annual retainer of $5,000 in cash in the second and
fourth quarters of each year. Members of the Audit Committee
receive an additional annual retainer of $2,500 in cash in the
second and fourth quarters of each year. During 2016, no additional
compensation was paid to non-employee directors for serving on the
MLP Conversion Special Committee. Non-employee directors serving on
the Compensation Committee do not receive additional compensation.
Non-employee directors are reimbursed for reasonable out-of-pocket
expenses related to in-person meeting attendance.
Stock Awards
. For service on the Board, non-employee
directors are entitled to receive Blue Dolphin Common Stock with a
fair value of $10,000 for services rendered in the first and third
quarters of each year. The number of shares of Common Stock issued
is determined by the closing price of Blue Dolphin’s Common
Stock on the last trading day in the respective quarterly period.
The shares of Common Stock are subject to resale restrictions
applicable to restricted securities and securities held by
affiliates under federal securities laws.
Remainder
of Page Intentionally Left Blank
96
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
This
table shows the compensation that each independent director earned
for his Board and committee service for the year ended December 31,
2016:
|
|
Years Ended December 31,
|
|||||
|
|
2016
|
2015
|
||||
|
Name
|
Stock
Awards
(1)(2)
|
Cash
Fees
(3)
|
Total Compensation
|
Stock
Awards
(1)(2)
|
Cash
Fees
(3)
|
Total Compensation
|
|
|
|
|
|
|
|
|
|
Christopher
T. Morris
|
$
30,000
|
$
25,000
|
$
55,000
|
$
20,000
|
$
28,750
|
$
48,750
|
|
Amitav
Misra
|
30,000
|
22,500
|
52,500
|
20,000
|
24,375
|
44,375
|
|
Ryan
A. Bailey
|
20,001
|
22,500
|
42,501
|
-
|
10,625
|
10,625
|
|
|
|
|
|
|
|
-
|
|
|
$
80,001
|
$
70,000
|
150,001
|
$
40,000
|
$
63,750
|
$
103,750
|
|
(1)
|
At
December 31, 2016, Messrs. Morris, Misra, and Bailey had total
restricted awards of Common Stock outstanding of 19,788, 11,529,
and 5,438, respectively.
|
|
(2)
|
In
accordance with SEC rules, the grant date fair value of
non-employee and independent director stock awards is calculated by
multiplying the number of shares of Common Stock awarded by the
closing price of Blue Dolphin’s Common Stock on the grant
date, which was $4.75 at March 31, 2016 and $3.00 at September 30,
2016. Based on the calculation, the aggregate grant date fair value
of non-employee director stock awards for services rendered for the
first and third quarters of 2016 was $30,000 and $20,001,
respectively.
|
|
(3)
|
Cash
fees reflects cash compensation that has been earned. Fees that
have not been paid are reflected within accrued expenses and other
current liabilities on our consolidated balance sheets. See
“Part II, Item 8. Financial Statements and Supplementary
Data, Note (9) Accrued Expenses and Other Current
Liabilities” within this Annual Report for additional
disclosures related to board of director fees payable.
|
Security Ownership of Certain Beneficial Owners
The
table below sets forth information with respect to persons or
groups known to us to be the beneficial owners of more than five
percent (5%) of our common stock at December 31, 2016. Unless
otherwise indicated, each named party has sole voting and
dispositive power with respect to such shares.
|
Title of Class
|
Name of Beneficial Owner
|
Amount and Nature of Beneficial
Ownership
|
Percent of
Class
(1)
|
|
|
|
|
|
|
Common Stock
|
Lazarus Energy Holdings, LLC
|
8,426,456
|
80.4%
|
|
|
801 Travis Street, Suite 2100
|
|
|
|
|
Houston, Texas 77002
|
|
|
(1)
Based upon
10,474,714 shares of Common Stock outstanding (10,624,714 shares of
Common Stock issued less 150,000 shares of Common Stock held in
treasury at December 31, 2016.)
97
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Security Ownership of Management
The
table below sets forth information at December 31, 2016 with
respect to: (i) directors, (ii) executive officers and (iii)
directors and executive officers as a group beneficially owning our
common stock. Unless otherwise indicated, each of the following
persons has sole voting and dispositive power with respect to such
shares.
|
Title of Class
|
Name of Beneficial Owner
|
Amount and Nature of Beneficial
Ownership
|
Percent of
Class
(1)
|
|
|
|
|
|
|
Common Stock
|
Jonathan P. Carroll
(2)
|
8,428,214
|
80.5%
|
|
Common Stock
|
Christopher T. Morris
|
19,788
|
*
|
|
Common Stock
|
Amitav Misra
|
11,529
|
*
|
|
Common Stock
|
Herbert N. Whitney
|
9,683
|
*
|
|
Common Stock
|
Ryan A. Bailey
|
5,438
|
---
|
|
Common Stock
|
Tommy L. Byrd
|
---
|
---
|
|
|
|
|
|
|
Directors/Nominees and Executive Officers as a Group (6
Persons)
|
8,474,652
|
80.9%
|
|
(1)
Based upon
10,474,714 shares of Common Stock outstanding (10,624,714 shares of
Common Stock issued less 150,000 shares of Common Stock held in
treasury at December 31, 2016). At December 31, 2016, there were no
options outstanding, no options exercisable or no shares of common
stock reserved for issuance under the 2000 Stock Incentive
Plan.
(2)
Includes 8,426,456
shares issued to Lazarus Energy Holdings, LLC (“LEH”).
Mr. Carroll and his affiliates have an approximate 60% ownership
interest in LEH.
* Less
than 1%.
Section 16(a) Beneficial Ownership Reporting
Compliance
Section
16(a) of the Exchange Act requires our directors, executive
officers and stockholders who own more than ten percent (10%) of
our Common Stock to file reports of stock ownership and changes in
ownership with the SEC and to furnish us with copies of all such
reports as filed. Based solely on a review of the copies of the
Section 16(a) reports furnished to us, we are unaware of any late
filings made during 2016.
Equity Compensation Plan Information
None.
Related Party Transactions
We are
party to several agreements with related parties. We believe these
related party transactions were consummated on terms equivalent to
those that prevail in arm's-length transactions. A summary of these
agreements follows:
LEH
. We are party to an Operating Agreement, a Product Sales
Agreement, a Terminal Services Agreement, a Loan and Security
Agreement, and a Promissory Note with LEH. LEH, our controlling
shareholder, owns approximately 81% of our Common Stock. Jonathan
Carroll, Chairman of the Board, Chief Executive Officer, and
President of Blue Dolphin, is the majority owner of
LEH.
98
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Operating Agreement
. LEH manages and operates all our
properties pursuant to the Operating Agreement. The Operating
Agreement expires upon the earliest to occur of: (a) the date of
the termination of the Joint Marketing Agreement pursuant to its
terms, (b) August 2018, or (c) upon written notice of either party
to the Operating Agreement of a material breach of the Operating
Agreement by the other party. For services rendered under the
Operating Agreement, LEH receives reimbursements and fees as
follows:
●
Reimbursements –
For management
and operation of all properties excluding the Nixon Facility, LEH
is reimbursed at cost for all reasonable expenses incurred while
performing the services. Unsettled reimbursements to LEH are either
reflected within prepaid expenses and other current assets or
accounts payable, related party in our consolidated balance sheets.
(See “Note (5) Prepaid Expenses and Other Current
Assets” for additional disclosures with respect to prepaid
related party operating expenses.)
●
Fees –
For management and
operation of the Nixon Facility, LEH receives: (i) weekly payments
to cover direct expenses incurred, (ii) $0.25 for each bbl
processed at the Nixon Facility up to a maximum quantity of 10,000
bbls per day determined monthly, and (iii) $2.50 for each bbl
processed at the Nixon Facility more than 10,000 bbls per day
determined monthly. Amounts expensed as fees to LEH are reflected
within refinery operating expenses in our consolidated statements
of operations. Fees owed to LEH under the Operating Agreement are
reflected within accounts payable, related party in our
consolidated balance sheets.
Product Sales Agreement
. Under a Product Sales Agreement,
LEH purchases jet fuel and other products from the Nixon Facility
for resale to a government agency. The Product Sales Agreement
terminates on the earliest to occur of: (a) a one-year term
expiring March 31, 2017 plus a 30-day carryover or (b) delivery of
a maximum quantity of jet fuel as defined therein. Sales to LEH
under the Product Sales Agreement are reflected within refined
petroleum product sales in our consolidated statements of
operations.
Terminal Services Agreement
. Pursuant to a Terminal Services
Agreement, LEH leases a petroleum storage tank at the Nixon
Facility. The Terminal Services Agreement has an initial term of 12
months and automatically renews for additional terms of 6 months.
The parties may terminate the Terminal Services Agreement upon 45
days’ written notice. Rental fees received from LEH under the
Terminal Services Agreement are reflected within tank rental
revenue in our consolidated statements of operations.
Loan and Security Agreement
. In August 2016, BDPL entered a
loan and security agreement with LEH as evidenced by a promissory
note in the original principal amount of $4.0 million (the
“LEH Loan Agreement”). The LEH Loan Agreement matures
in August 2018, and accrues interest at rate of 16.00%. Under the
LEH Loan Agreement, BDPL will make payments to LEH of $500,000 per
year. A final balloon payment is due at maturity.
The
proceeds of the LEH Loan Agreement were used for working capital.
There are no financial maintenance covenants associated with the
LEH Loan Agreement. The LEH Loan Agreement is secured by certain
property owned by BDPL located in Brazoria County Texas.
Outstanding principal and interest less associated debt issue costs
owed to LEH under the LEH Loan Agreement are reflected in long-term
debt, related party, current portion and long-term debt, related
party, net of current portion in our consolidated balance
sheets.
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with LEH in the original principal amount of
$1,797,172 (the “LEH Note”). The LEH Note accrues
interest, compounded annually, at a rate of 8.00%. The principal
amount and any accrued but unpaid interest are due and payable in
January 2018. Under the LEH Note, prepayment, in whole or in part,
is permissible at any time and from time to time, without premium
or penalty. Outstanding principal and interest owed to LEH under
the LEH Note are reflected in long-term debt, related party, net of
current portion in our consolidated balance sheets. At December 31,
2016, the outstanding principal and interest on the LEH Note was
$0.
Ingleside Crude, LLC (“Ingleside”)
. We are party
to an Amended and Restated Tank Lease Agreement and a Promissory
Note with Ingleside. Ingleside is a related party of LEH and
Jonathan Carroll.
99
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Amended and Restated Tank Lease Agreement
. Pursuant to an
Amended and Restated Tank Lease Agreement with Ingleside, we lease
petroleum storage tanks to meet periodic, additional storage needs.
The Amended and Restated Tank Lease Agreement had an initial term
of 30 days with automatic 30-day renewal periods. The parties may
terminate the tank lease agreement upon 30 days’ written
notice. Rental fees owed to Ingleside under the tank lease
agreement are reflected within accounts payable, related party in
our consolidated balance sheets. Amounts expensed as rental fees to
Ingleside under the Amended and Restated Tank Lease Agreement are
reflected within refinery operating expenses in our consolidated
statements of operations.
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with Ingleside in the original principal amount of
$679,385 (the “Ingleside Note”). The principal amount
of the Ingleside Note was increased by $50,000 in the fourth
quarter of 2016. The Ingleside Note accrues interest, compounded
annually, at a rate of 8.00%. The principal amount and any accrued
but unpaid interest are due and payable in January 2018. Under the
Ingleside Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty.
Outstanding principal and interest owed to Ingleside under the
Ingleside Note are reflected in long-term debt, related party, net
of current portion in our consolidated balance sheets. At December
31, 2016, the outstanding principal and interest on the Ingleside
Note was $722,278.
Lazarus Marine Terminal I, LLC (“LMT”)
. We are
party to a Tolling Agreement with LMT. LMT is a related party of
LEH and Jonathan Carroll.
Tolling Agreement
. In May 2016, we entered a Tolling
Agreement with LMT to facilitate loading and unloading of our
petroleum products by barge at LMT’s dock facility in
Ingleside, Texas. The Tolling Agreement has a five-year term and
may be terminated at any time by the agreement of both parties. We
pay LMT a flat monthly reservation fee of $50,400. The monthly
reservation fee includes tolling volumes up to 84,000 gallons per
day. Tolling volumes more than 210,000 gallons per quarter are
billed to us at $0.02 per gallon. Amounts expensed as tolling fees
to LMT under the Tolling Agreement are reflected in cost of refined
products sold in our consolidated statements of
operations.
Jonathan Carroll
. We are party to Guaranty Fee Agreements
and a Promissory Note with Jonathan Carroll. Jonathan Carroll is
Chairman of the Board, Chief Executive Officer, and President of
Blue Dolphin.
Guaranty Fee Agreements
. Pursuant to Guaranty Fee
Agreements, Jonathan Carroll receives fees for providing his
personal guarantee on certain of our long-term debt. Jonathan
Carroll was required to guarantee repayment of funds borrowed and
interest accrued under certain loan agreements. Amounts owed to
Jonathan Carroll under Guaranty Fee Agreements are reflected within
accounts payable, related party in our consolidated balance sheets.
Amounts expensed related to Guarantee Fee Agreements are reflected
within interest and other expense in our consolidated statements of
operations. (See “Note (10) Long-Term Debt, Net” for
further discussion related to the Guaranty Fee
Agreements.)
Promissory Note
. In September 2016, Blue Dolphin entered a
promissory note with Jonathan Carroll in the original principal
amount of $422,374 (the “Carroll Note”). The principal
amount of the Carroll Note was increased by $170,038 in the fourth
quarter of 2016. The Carroll Note accrues interest, compounded
annually, at a rate of 8.00%. The principal amount and any accrued
but unpaid interest are due and payable in January 2018. Under the
Carroll Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty.
Outstanding principal and interest owed to Jonathan Carroll under
the Carroll Note are reflected in long-term debt, related party,
net of current portion in our consolidated balance sheets. At
December 31, 2016, the outstanding principal and interest on the
Carroll Note was $592,412.
Director Independence
The
Board has affirmatively determined that each of its members, except
for Messrs. Carroll and Whitney, are independent and have no
material relationship with us (either directly or indirectly or as
a stockholder or officer of an organization that has a relationship
with us), and that all members of the Audit Committee, Compensation
Committee, and MLP Conversion Special Committee are
independent, pursuant to OTCQX and SEC rules. Mr. Whitney serves as
a consultant to LEH.
100
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Fees
paid to UHY by us were as follow:
|
|
Years Ended December 31,
|
|
|
|
2016
|
2015
|
|
|
|
|
|
Audit
fees
|
$
136,826
|
$
176,660
|
|
Audit-related
fees
|
-
|
-
|
|
Tax
fees
|
-
|
-
|
|
All
other fees
|
-
|
-
|
|
|
|
|
|
|
$
136,826
|
$
176,660
|
Audit
fees for 2016 and 2015 related to the audit of our consolidated
financial statements and the review of our quarterly reports that
are filed with the SEC. The Audit Committee must pre-approve all
audit and non-audit services provided to us by our independent
registered public accounting firm.
Remainder
of Page Intentionally Left Blank
101
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
Exhibits and Financial Statement Schedules
Following
is a list of documents filed as part of this Annual
Report:
●
consolidated
balance sheets, consolidated statements of operations, consolidated
statements of shareholders’ equity, and consolidated
statements of cash flows, which appear in “Part II, Item 8.
Financial Statements and Supplementary Data” of this Annual
Report; and
●
exhibits as listed
in the exhibit index of this Annual Report, which is incorporated
herein by reference.
Not
applicable.
Exhibits Index
|
No.
|
Description
|
|
3.1
|
Amended
and Restated Certificate of Incorporation of Blue Dolphin
(incorporated by reference to Exhibit 3.1 filed with Blue
Dolphin’s Form 8-K on June 2, 2009, Commission File No.
000-15905)
|
|
3.2
|
Amended
and Restated By-Laws of Blue Dolphin (incorporated by reference to
Exhibit 3.1 filed with Blue Dolphin’s Form 8-K on December
26, 2007, Commission File No. 000-15905)
|
|
4.1
|
Specimen
Stock Certificate (incorporated by reference to exhibits filed with
Blue Dolphin’s Form 10-K on March 30, 1990, Commission File
No. 000-15905)
|
|
4.2
|
Form of
Promissory Note issued pursuant to the Note and Warrant Purchase
Agreement dated September 8, 2004 (incorporated by reference to
Exhibit 4.1 filed with Blue Dolphin’s Form 8-K on September
14, 2004, Commission File No. 000-15905)
|
|
4.3
|
Promissory
Note of Lazarus Louisiana Refinery II, LLC, payable to Blue Dolphin
dated July 31, 2009 (incorporated by reference to Exhibit 10.1
filed with Blue Dolphin’s Form 8-K on August 6, 2009,
Commission File No. 000-15905)
|
|
10.1
|
Blue
Dolphin 2000 Stock Incentive Plan (incorporated by reference to
Appendix 1 filed with Blue Dolphin’s Proxy Statement on Form
DEF 14A on April 20, 2000, Commission File No. 000-15905)
*
|
|
10.2
|
First
Amendment to the Blue Dolphin 2000 Stock Incentive Plan
(incorporated by reference to Appendix B filed with Blue
Dolphin’s Proxy Statement on Form DEF 14A on April 16, 2003,
Commission File No. 000-15905) *
|
|
10.3
|
Second
Amendment to the Blue Dolphin 2000 Stock Incentive Plan
(incorporated by reference to Appendix A filed with Blue
Dolphin’s Proxy Statement on Form DEF 14A on April 27, 2006,
Commission File No. 000-15905) *
|
|
10.4
|
Fourth
Amendment to the Blue Dolphin 2000 Stock Incentive Plan
(incorporated by reference to Exhibit B filed with Blue
Dolphin’s Proxy Statement on Form DEFA on December 28, 2011,
Commission File No. 000-15905) *
|
|
|
|
102
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
10.5
|
Master
Easement Agreement effective as of December 11, 2013 by and between
Blue Dolphin Pipe Line Company and FLNG Land, II, Inc.
(incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 8-K on November 5, 2014, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.6
|
Letter
of Intent effective as of December 11, 2013 by and between Blue
Dolphin Pipe Line Company and Freeport LNG Expansion, L.P
(incorporated by reference to Exhibit 10.2 filed with Blue
Dolphin’s Form 8-K on November 5, 2014, Commission File No.
000-15905)
|
|
|
10.7
|
Management
Agreement by and between Lazarus Energy Holdings, LLC, Lazarus
Energy, LLC and Blue Dolphin effective as of February 15, 2012
(incorporated by reference to Exhibit 10.2 filed with Amendment No.
1 to Blue Dolphin’s Form 8-K on March 14, 2012, Commission
File No. 000-15905)
|
|
|
|
|
|
|
10.8
|
Amendment
No. 1 to Management Agreement dated May 12, 2014 by and among
Lazarus Energy Holdings, LLC, Blue Dolphin and Lazarus Energy, LLC
(incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 8-K on May 16, 2014, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.9
|
Crude
Oil Supply and Throughput Services Agreement by and between GEL Tex
Marketing, LLC and Lazarus Energy, LLC dated as of August 12, 2011
(incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 10-Q on June 30, 2012, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.10
|
Joint
Marketing Agreement by and between GEL Tex Marketing, LLC and
Lazarus Energy, LLC dated as of August 12, 2011 (incorporated by
reference to Exhibit 10.3 filed with Blue Dolphin’s Form 10-Q
on June 30, 2012, Commission File No. 000-15905)
|
|
|
10.11
|
Letter
Agreement dated September 12, 2011 between GEL Tex Marketing, LLC,
Milam Services, Inc., 1st International Bank, Lazarus Energy LLC
and Lazarus Energy Holdings LLC (incorporated by reference to
Exhibit 10.4 filed with Blue Dolphin’s Form 10-Q on March 31,
2012, Commission File No. 000-15905)
|
|
10.12
|
Acknowledgment
Letter between Lazarus Energy, LLC and GEL Tex Marketing, LLC dated
June 1, 2012 (incorporated by reference to Exhibit 10.4 filed with
Blue Dolphin’s Form 10-Q on June 30, 2012, Commission File
No. 000-15905)
|
|
10.13
|
Letter
Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC
dated June 25, 2012 (incorporated by reference to Exhibit 10.5
filed with Blue Dolphin’s Form 10-Q on June 30, 2012,
Commission File No. 000-15905)
|
|
10.14
|
Letter
Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC
dated July 30, 2012 (incorporated by reference to Exhibit 10.6
filed with Blue Dolphin’s Form 10-Q on June 30, 2012,
Commission File No. 000-15905)
|
|
10.15
|
Letter
Agreement between Lazarus Energy, LLC and GEL Tex Marketing, LLC
dated August 1, 2012 (incorporated by reference to Exhibit 10.7
filed with Blue Dolphin’s Form 10-Q on June 30, 2012,
Commission File No. 000-15905)
|
|
10.16
|
Letter
Agreement dated June 10, 2012 between Lazarus Energy Holdings, LLC
and Blue Dolphin Energy Company (incorporated by reference to
Exhibit 10.1 filed with Blue Dolphin’s Form 8-K on June 14,
2012, Commission File No. 000-15905)
|
|
10.17
|
Letter
Agreement dated December 20, 2012 between Lazarus Energy, LLC, GEL
Tex Marketing, LLC and Milam Services, Inc. (incorporated by
reference to Exhibit 10.35 filed with Blue Dolphin’s Form
10-K on March 30, 2013, Commission File No. 000-15905)
|
|
|
|
|
|
|
10.18
|
Letter
Agreement between Lazarus Energy, LLC, GEL TEX Marketing, LLC and
Milam Services, Inc. dated February 21, 2013 (incorporated by
reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q
on August 14, 2013, Commission File No. 000-15905)
|
|
|
|
|
|
|
10.19
|
Letter
Agreement between Lazarus Energy, LLC, GEL TEX Marketing, LLC and
Milam Services, Inc. dated February 21, 2013 (incorporated by
reference to Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q
on May 15, 2013, Commission File No. 000-15905)
|
|
|
|
|
|
|
10.20
|
Letter
Agreement Regarding Certain Advances and Related Agreement between
Lazarus Energy, LLC, GEL TEX Marketing, LLC, and Milam Services,
Inc., effective October 24, 2013 (incorporated by reference to
Exhibit 10.2 filed in connection with Blue Dolphin’s Form
10-Q on November 14, 2013, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.21
|
Promissory
Note between Lazarus Energy LLC as maker and Notre Dame Investors
Inc. as Payee in the Principal Amount of $8,000,000 dated June 1,
2006 (incorporated by reference to Exhibit 10.6 filed with Blue
Dolphin’s Form 10-Q on March 31, 2012, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.22
|
Subordination
Agreement effective August 21, 2008 by Notre Dame Investors, Inc.
in favor of First International Bank (incorporated by reference to
Exhibit 10.2 filed with Blue Dolphin’s Form 10-Q on March 31,
2012, Commission File No. 000-15905)
|
|
|
|
|
|
|
10.23
|
Intercreditor
and Subordination Agreement dated September 29, 2008 by and between
Notre Dame Investors, Inc., Richard Oberlin, Lazarus Energy LLC and
First International Bank (incorporated by reference to Exhibit 10.3
filed with Blue Dolphin’s Form 10-Q on March 31, 2012,
Commission File No. 000-15905)
|
|
|
|
|
|
|
10.24
|
Intercreditor
and Subordination Agreement dated August 12, 2011 by and among John
H. Kissick, Lazarus Energy LLC and Milam Services, Inc.
(incorporated by reference to Exhibit 10.7 filed with Blue
Dolphin’s Form 10-Q on March 31, 2012, Commission File No.
000-15905)
|
|
|
|
|
|
|
10.25
|
First
Amendment to Promissory Note by and between Lazarus Energy, LLC and
John H. Kissick effective as of July 1, 2013 (incorporated by
reference to Exhibit 10.1 filed with Blue Dolphin’s Form 10-Q
on November 14, 2013, Commission File No. 000-15905)
|
|
|
|
|
|
|
10.26
|
Second
Amendment to Promissory Note by and between Lazarus Energy, LLC and
John H. Kissick effective as of October 1, 2014 (incorporated by
reference to Exhibit 10.48 filed with Blue Dolphin’s Form
10-K on March 31, 2015, Commission File No. 000-15905)
|
|
|
10.27
|
Loan
and Security Agreement dated March 2, 2014 by and between Lazarus
Refining & Marketing, LLC and Sovereign Bank (incorporated by
reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K
on May 8, 2014, Commission File No. 000-15905)
|
|
|
|
|
10.28
|
Deed of
Trust, Security Agreement, Assignment of Leases, Assignment of
Rents, and Financing Statement dated May 2, 2014 (incorporated by
reference to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K
on May 8, 2014, Commission File No. 000-15905)
|
|
|
|
|
10.29
|
Guaranty
Agreement dated May 2, 2014 by Jonathan P. Carroll and Ingleside
Crude LLC for the benefit of Sovereign Bank (incorporated by
reference to Exhibit 10.3 filed with Blue Dolphin’s Form 8-K
on May 8, 2014, Commission File No. 000-15905)
|
|
|
|
|
10.30
|
Pledge
Agreement dated May 2, 2014 between Sovereign Bank and Lazarus
Energy Holdings, LLC. (incorporated by reference to Exhibit 10.4
filed with Blue Dolphin’s Form 8-K on May 8, 2014, Commission
File No. 000-15905)
|
|
|
|
|
10.31
|
Promissory
Note payable to Sovereign Bank dated May 2, 2014 (incorporated by
reference to Exhibit 10.5 filed with Blue Dolphin’s Form 8-K
on May 8, 2014, Commission File No. 000-15905)
|
|
|
|
|
10.32
|
Collateral
Assignment dated May 2, 2014 by Lazarus Refining & Marketing,
LLC for the benefit of Sovereign Bank (incorporated by reference to
Exhibit 10.6 filed with Blue Dolphin’s Form 8-K on May 8,
2014, Commission File No. 000-15905)
|
|
|
|
103
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
10.33
|
Collateral
Assignment dated May 2, 2014 by Lazarus Refining & Marketing,
LLC for the benefit of Sovereign Bank (incorporated by reference to
Exhibit 10.7 filed with Blue Dolphin’s Form 8-K on May 8,
2014, Commission File No. 000-15905)
|
|
|
|
|
10.34
|
Loan
Modification Agreement dated March 25, 2015, by and between Lazarus
Refining & Marketing, LLC, and Sovereign Bank (incorporated by
reference to Exhibit 10.1 filed with Blue Dolphin’s Form 8-K
on March 31, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.35
|
Second
Amendment to Promissory Note by and between Lazarus Energy, LLC and
John H. Kissick effective as of October 1, 2014 (incorporated by
reference to Exhibit 10.48 filed with Blue Dolphin’s Form
10-K on March 31, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.36
|
Loan
Agreement among Sovereign Bank, Lazarus Energy, LLC and Jonathan
Pitts Carroll, Sr., Blue Dolphin Energy Company, Lazarus Refining
& Marketing, LLC, and Lazarus Energy Holdings dated June 22,
2015 (incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 8-K on June 26, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.37
|
Promissory
Note between Lazarus Energy, LLC and Sovereign Bank for the
principal sum of $25,000,000 dated June 22, 2015 (incorporated by
reference to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K
on June 26, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.38
|
Security
Agreement of Lazarus Energy, LLC in favor of Sovereign Bank dated
June 22, 2015 (incorporated by reference to Exhibit 10.3 filed with
Blue Dolphin’s Form 8-K on June 26, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.39
|
Deed of
Trust, Mortgage, Security Agreement, Assignment of Leases and
Rents, Financing Statement and Fixture Filing for Lazarus Energy,
LLC dated June 22, 2015 (incorporated by reference to Exhibit 10.4
filed with Blue Dolphin’s Form 8-K on June 26, 2015,
Commission File No. 000-15905)
|
|
10.40
|
Security
Agreement of Lazarus Energy, LLC for the benefit of Lazarus
Refining & Marketing, LLC dated June 22, 2015 (incorporated by
reference to Exhibit 10.5 filed with Blue Dolphin’s Form 8-K
on June 26, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.41
|
Loan
and Security Agreement between Sovereign Bank and Lazarus Refining
& Marketing, LLC dated June 22, 2015 (incorporated by reference
to Exhibit 10.6 filed with Blue Dolphin’s Form 8-K on June
26, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.42
|
Promissory
Note between Lazarus Refining & Marketing, LLC and Sovereign
Bank for the principal sum of $3,000,000 dated June 22, 2015
(incorporated by reference to Exhibit 10.7 filed with Blue
Dolphin’s Form 8-K on June 26, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.43
|
Pledge
Agreement by Lazarus Refining & Marketing, LLC in favor of
Sovereign Bank dated June 22, 2015 (incorporated by reference to
Exhibit 10.8 filed with Blue Dolphin’s Form 8-K on June 26,
2015, Commission File No. 000-15905)
|
|
|
|
|
10.44
|
Collateral
Assignment executed by Blue Dolphin Pipe Line Company for the
benefit of Sovereign Bank dated June 22, 2015 (incorporated by
reference to Exhibit 10.9 filed with Blue Dolphin’s Form 8-K
on June 26, 2015, Commission File No. 000-15905)
|
|
|
|
104
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
10.45
|
Guaranty
Agreement by Jonathan Pitts Carroll, Sr., Blue Dolphin Energy
Company, Lazarus Energy, LLC and Sovereign Bank dated June 22, 2015
(incorporated by reference to Exhibit 10.10 filed with Blue
Dolphin’s Form 8-K on June 26, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.46
|
Guaranty
Fee Agreement between Jonathan P. Carroll and Lazarus Energy, LLC
dated June 22, 2015 (incorporated by reference to Exhibit 10.11
filed with Blue Dolphin’s Form 8-K on June 26, 2015,
Commission File No. 000-15905)
|
|
|
|
|
10.47
|
Guaranty
Fee Agreement between Jonathan P. Carroll and Lazarus Refining
& Marketing, LLC dated June 22, 2015 (incorporated by reference
to Exhibit 10.12 filed with Blue Dolphin’s Form 8-K on June
26, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.48
|
Amendment
No. 2. to Operating Agreement by and between Lazarus Energy
Holdings, LLC, Blue Dolphin, and Lazarus Energy, LLC effective as
of June 1, 2015 (incorporated by reference to Exhibit 10.1 filed
with Blue Dolphin’s Form 10-Q on August 14, 2015, Commission
File No. 000-15905)
|
|
|
|
|
10.49
|
Loan
Agreement among Sovereign Bank, Lazarus Refining & Marketing,
LLC, Jonathan Pitts Carroll, Sr., Blue Dolphin Energy Company,
Lazarus Energy, LLC, and Lazarus Energy Holdings dated December 4,
2015 (incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 8-K on December 10, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.50
|
Promissory
Note between Lazarus Refining & Marketing, LLC and Sovereign
Bank for the principal sum of $10,000,000 dated December 4, 2015
(incorporated by reference to Exhibit 10.2 filed with Blue
Dolphin’s Form 8-K on December 10, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.51
|
Security
Agreement of Lazarus Refining & Marketing, LLC in favor of
Sovereign Bank dated December 4, 2015 (incorporated by reference to
Exhibit 10.3 filed with Blue Dolphin’s Form 8-K on December
10, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.52
|
Deed of
Trust, Mortgage, Security Agreement, Assignment of Leases and
Rents, Financing Statement and Fixture Filing for Lazarus Refining
& Marketing, LLC dated December 4, 2015 (incorporated by
reference to Exhibit 10.4 filed with Blue Dolphin’s Form 8-K
on December 10, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.53
|
Construction
Rider to Loan Agreement dated December 4, 2015 (incorporated by
reference to Exhibit 10.5 filed with Blue Dolphin’s Form 8-K
on December 10, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.54
|
Absolute
Assignment of Leases and Rents dated December 4, 2015 (incorporated
by reference to Exhibit 10.6 filed with Blue Dolphin’s Form
8-K on December 10, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.55
|
Indemnification
Agreement dated December 4, 2015 (incorporated by reference to
Exhibit 10.7 filed with Blue Dolphin’s Form 8-K on December
10, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.56
|
Pledge
Agreement by Lazarus Energy Holdings, LLC in favor of Sovereign
Bank dated December 4, 2015 (incorporated by reference to Exhibit
10.8 filed with Blue Dolphin’s Form 8-K on December 10, 2015,
Commission File No. 000-15905)
|
|
|
|
|
10.57
|
Collateral
Assignment of Key Agreements dated December 4, 2015 (incorporated
by reference to Exhibit 10.9 filed with Blue Dolphin’s Form
8-K on December 10, 2015, Commission File No.
000-15905)
|
|
|
|
|
10.58
|
First
Amendment to Lazarus Energy, LLC Loan Agreement and Loan Documents
dated December 4, 2015 (incorporated by reference to Exhibit 10.10
filed with Blue Dolphin’s Form 8-K on December 10, 2015,
Commission File No. 000-15905)
|
|
|
|
|
10.59
|
First
Amendment to Lazarus Energy, LLC Deed of Trust, Mortgage, Security
Agreement, Assignment of Leases and Rents, Financing Statement and
Fixture Filing dated December 4, 2015 (incorporated by reference to
Exhibit 10.11 filed with Blue Dolphin’s Form 8-K on December
10, 2015, Commission File No. 000-15905)
|
|
|
|
|
10.60
|
Guaranty
Fee Agreement between Jonathan P. Carroll and Lazarus Refining
& Marketing, LLC dated December 4, 2015 (incorporated by
reference to Exhibit 10.12 filed with Blue Dolphin’s Form 8-K
on December 10, 2015, Commission File No. 000-15905)
|
|
10.61
|
Loan
and Security Agreement by and between Lazarus Energy Holdings, LLC
and Blue Dolphin Pipe Line Company dated August 15, 2016
(incorporated by reference to Exhibit 10.1 filed with Blue
Dolphin’s Form 8-K on August 19, 2016, Commission File No.
000-15905)
|
105
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
2016
FORM 10-K
|
|
10.62
|
Promissory
Note by and between Lazarus Energy Holdings, LLC and Blue Dolphin
Pipe Line Company dated August 15, 2016 (incorporated by reference
to Exhibit 10.2 filed with Blue Dolphin’s Form 8-K on August
19, 2016, Commission File No. 000-15905)
|
|
10.63
|
Deed of
Trust, Mortgage, Security Agreement, Assignment of Leases and
Rents, Financing Statement and Fixture Filing for Blue Dolphin Pipe
Line Company dated August 15, 2016 (incorporated by reference to
Exhibit 10.3 filed with Blue Dolphin’s Form 8-K on August 19,
2016, Commission File No. 000-15905)
|
|
10.64
|
Collateral Assignment of Master Easement Agreement by Blue Dolphin
Pipe Line Company for the benefit of Lazarus Energy Holdings, LLC
dated August 15, 2016 (incorporated by reference to Exhibit 10.4
filed with Blue Dolphin’s Form 8-K on August 19, 2016,
Commission File No. 000-15905)
|
|
14.1
|
Code of
Ethics applicable to the Chairman, Chief Executive Officer and
Senior Financial Officer (incorporated by reference to Exhibit 14.1
filed with Blue Dolphin’s Form 10-KSB on March 25, 2005,
Commission File No. 000-15905)
|
|
21.1
|
List of
Subsidiaries of Blue Dolphin **
|
|
23.1
|
Consent
of UHY LLP **
|
|
31.1
|
Jonathan
P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 302 of the Sarbanes-Oxley Act of
2002 **
|
|
31.2
|
Tommy
L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 302 of the Sarbanes-Oxley Act of 2002
**
|
|
32.1
|
Jonathan
P. Carroll Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002
**
|
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32.2
|
Tommy
L. Byrd Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002
**
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99.1
|
Amended
and Restated Audit Committee Charter adopted by the Board of
Directors of Blue Dolphin on November 4, 2015 (incorporated by
reference to Appendix A filed with Blue Dolphin’s Proxy
Statement on Form DEF 14A on November 18, 2015, Commission File No.
000-15905)
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99.2
|
Compensation
Committee Charter adopted by the Board of Directors of Blue Dolphin
on November 4, 2015 (incorporated by reference to Appendix B filed
with Blue Dolphin’s Proxy Statement on Form DEF 14A on
November 18, 2015, Commission File No. 000-15905)
|
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101.INS
|
XBRL
Instance Document **
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|
101.SCH
|
XBRL
Taxonomy Schema Document **
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|
101.CAL
|
XBRL
Calculation Linkbase Document **
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|
101.LAB
|
XBRL
Label Linkbase Document **
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101.PRE
|
XBRL
Presentation Linkbase Document **
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101.DEF
|
XBRL
Definition Linkbase Document **
|
_______________
*
Management Compensation Plan
**
Filed herewith
106
|
BLUE
DOLPHIN ENERGY COMPANY
|
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2016
FORM 10-K
|
Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this Annual Report to be
signed on its behalf by the undersigned, thereunto duly
authorized.
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BLUE DOLPHIN ENERGY COMPANY
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(Registrant)
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March
31, 2017
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By:
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/s/
JONATHAN P. CARROLL
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|
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Jonathan
P. Carroll
Chief
Executive Officer, President,
Assistant
Treasurer and Secretary
(Principal
Executive Officer)
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|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this
Annual Report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
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Signature
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Title
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Date
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/s/
JONATHAN P. CARROLL
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Jonathan
P. Carroll
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Chairman
of the Board, Chief Executive Officer, President, Assistant
Treasurer and Secretary (Principal Executive Officer)
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|
March
31, 2017
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/s/
TOMMY L. BYRD
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Tommy
L. Byrd
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Chief
Financial Officer,
Treasurer
and Assistant Secretary
(Principal
Financial Officer)
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|
March
31, 2017
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/s/
RYAN A. BAILEY
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Ryan A.
Bailey
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Director
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March
31, 2017
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/s/
AMITAV MISRA
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Amitav
Misra
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Director
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|
March
31, 2017
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/s/
CHRISTOPHER T. MORRIS
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Christopher
T. Morris
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Director
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March
31, 2017
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/s/
HERBERT N. WHITNEY
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Director
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March
31, 2017
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Herbert
N. Whitney
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107
TABLE OF CONTENTS
Part I, Item 1A. Risk FactorsPart Ii, Item 7. Management S Discussion and Analysis Of Financial Condition and Results Of Operations:Part Ii, Item 8. Financial Statements and Supplementary Data:Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits, Financial Statement SchedulesItem 16. Form 10-k Summary