Company Overview
Blue Dolphin, a
Delaware corporation formed in 1986, is an independent refiner and
marketer of petroleum products. We also conduct
petroleum storage and terminaling operations under third-party
lease agreements. Our primary operating asset is a 15,000-bpd crude
oil and condensate processing facility in Nixon, Texas (the
“Nixon Facility”). Blue Dolphin maintains a
website at
http://www.blue-dolphin-energy.com
. Information
on or accessible through Blue Dolphin’s website is not
incorporated by reference in or otherwise made a part of this
Annual Report.
Structure and Management
Corporate
Structure
Blue Dolphin
operates a single business segment – Refinery
Operations. Refinery operations are conducted at the
Nixon Facility through the following subsidiaries:
●
Lazarus Energy,
LLC, a Delaware limited liability company
(“LE”).
●
Lazarus Refining
& Marketing, LLC, a Delaware limited liability company
(“LRM”).
Blue Dolphin owns
pipeline assets and has leasehold interests in oil and gas
wells. These assets, which are not operational, are
included in Corporate and Other. Corporate and Other
includes the following subsidiaries:
●
Blue Dolphin Pipe
Line Company, a Delaware corporation
(“BDPL”).
●
Blue Dolphin
Petroleum Company, a Delaware corporation
(“BDPC”).
●
Blue Dolphin
Services Co., a Texas corporation
(“BDSC”).
See "Part I, Item
2. Properties” for additional information regarding our
operating subsidiaries, facilities, and assets.
Management
Blue Dolphin is
controlled by Lazarus Energy Holdings, LLC (“LEH”). LEH
operates and manages all Blue Dolphin properties pursuant to an
Amended and Restated Operating Agreement (the “Amended and
Restated 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. Together LEH and Jonathan Carroll own
80.2% of our common stock, par value $0.01 per share (the
“Common Stock). (See “Part II, Item 8. Financial
Statements and Supplementary Data – Note (8) Related Party
Transactions, Note (10) Long-Term Debt, Net and Note (19)
Commitments and Contingencies – Financing Agreements”
for additional disclosures related to LEH, the Amended and Restated
Operating Agreement, and Jonathan Carroll.)
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Going Concern
Management has
determined that certain factors raise substantial doubt about our
ability to continue as a going concern. These factors
include the following:
●
Final GEL
Arbitration Award – As previously disclosed, LE was involved
in arbitration proceedings (the “GEL Arbitration”) with
GEL Tex Marketing, LLC (“GEL”), an affiliate of Genesis
Energy, LP (“Genesis”), related to a contractual
dispute involving a Crude Oil Supply and Throughput Services
Agreement (the “Crude Supply Agreement”) and a Joint
Marketing Agreement (the “Joint Marketing Agreement”),
each between LE and GEL and dated August 12, 2011. On
August 11, 2017, the arbitrator delivered its final award in the
GEL Arbitration (the “Final Arbitration
Award”). The Final Arbitration Award denied all
LE’s claims against GEL and granted substantially all the
relief requested by GEL in its counterclaims. Among
other matters, the Final Arbitration Award awarded damages and
GEL’s attorneys’ fees and related expenses to GEL in
the aggregate amount of approximately $31.3
million.
As previously
disclosed, a hearing on confirmation of the Final Arbitration Award
was scheduled to occur on September 18, 2017 in state district
court in Harris County, Texas. Prior to the scheduled hearing, LE
and GEL jointly notified the court that the hearing would be
continued for a period of no more than 90 days after September 18,
2017 (the “Continuance Period”), to facilitate
settlement discussions between the parties. On September 26, 2017,
LE and Blue Dolphin, together with LEH and Jonathan Carroll,
entered into a Letter Agreement with GEL, effective September 18,
2017 (the “GEL Letter Agreement”), confirming the
parties’ agreement to the continuation of the confirmation
hearing during the Continuance Period, subject to the terms of the
GEL Letter Agreement.
The GEL Letter
Agreement has been amended to extend the Continuance Period through
April 30, 2018. The GEL Letter Agreement, as amended to
date, prohibits Blue Dolphin and its affiliates from making any
pre-payments on indebtedness, other than in the ordinary course of
business as described in the GEL Letter Agreement, and from making
any payments to Jonathan Carroll under the Amended and Restated
Guaranty Fee Agreements between November 1, 2017 and the end of the
Continuance Period. (Jonathan Carroll has received no
cash payments since August 2016 and no common stock payments since
May 2017 under the Amended and Restated Guaranty Fee
Agreements.) If the parties are unable to reach an
acceptable settlement with Genesis and GEL, and GEL seeks to
confirm and enforce the Final Arbitration Award against LE, our
business, financial condition, and results of operations will be
materially affected, and LE would likely be required to seek
protection under bankruptcy laws.
●
Veritex Secured
Loan Agreement Event of Default – Veritex Community Bank
(“Veritex”), as successor in interest to Sovereign Bank
by merger, delivered to obligors notices of default under secured
loan agreements with Veritex, stating that the Final Arbitration
Award constitutes an event of default under the secured loan
agreements. The occurrence of an event of default
permits Veritex to declare the amounts owed under these loan
agreements immediately due and payable, exercise its rights with
respect to collateral securing obligors’ obligations under
these loan agreements, and/or exercise any other rights and
remedies available. Veritex informed obligors that it is
not currently exercising its rights and remedies under the secured
loan agreements considering the ongoing settlement discussions with
GEL and the continuance of the hearing on confirmation of the Final
Arbitration Award and to allow Veritex to evaluate any proposed
settlement agreement related to the Final Arbitration Award, which
would require Veritex’s approval. However, Veritex expressly
reserved all its rights, privileges and remedies related to events
of default under the secured loan agreements and informed obligors
that it would consider a final confirmation of the Final
Arbitration Award to be a material event of default under the loan
agreements. Any exercise by Veritex of its rights and remedies
under the secured loan agreements would have a material adverse
effect on our business, financial condition, and results of
operations and would likely require us to seek protection under
bankruptcy laws. The debt associated with loans under secured loan
agreements was classified within the current portion of long-term
debt on our consolidated balance sheet at December 31, 2017 due to
existing events of default related to the Final Arbitration Award
as well as the uncertainty of LE and LRM’s ability to meet
financial covenants in the secured loan agreements in the
future.
We are currently
evaluating the effects of the Final Arbitration Award on our
business, financial condition, and results of
operations. In addition to the matters described above,
the Final Arbitration Award could materially and adversely affect
our ability to procure adequate amounts of crude oil and condensate
or our relationships with our customers. The
contract-related dispute has negatively affected our customer
relationships, prevented us from taking advantage of business
opportunities, disrupted refinery operations, diverted
management’s focus away from running the business, and
impacted our ability to obtain financing.
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We can provide no
assurance as to whether negotiations with GEL will result in a
settlement, the potential terms of any such settlement, or whether
Veritex would approve any such settlement. If LE is
unable to reach an acceptable settlement with GEL or Veritex does
not approve any such settlement and GEL seeks to confirm and
enforce the Final Arbitration Award, our business, financial
condition, and results of operations will be materially adversely
affected and LE would likely be required to seek protection under
bankruptcy laws.
Operating Risks
Successful
execution of our business plan depends on several key factors,
including reaching an acceptable settlement with GEL, having
adequate crude oil and condensate supplies, , maintaining the safe
and reliable operation of the Nixon Facility, improving margins on
refined petroleum products, and meeting contractual obligations.
(See “Business Strategies” within this Part I, Item 1.
Business for information related to our business
plan.) For the year ended December 31, 2017, execution
of our business plan was negatively impacted by several factors,
including:
●
Net Losses –
For the year ended December 31, 2017, we reported a net loss of
$22,328,390, or a loss of $2.09 per share, compared to a net loss
of $15,767,448, or a loss of $1.51 per share, for the year ended
December 31, 2016. The $0.58 per share increase in net
loss between the periods was the result of the Final Arbitration
Award, which was partially offset by improved margins for refined
petroleum products and increased sales volume. The amount expensed
in the period related to the Final Arbitration Award was
$24,338,628, which represented $2.28 per
share. Excluding the Final Arbitration Award, we would
have reported net income of $0.19 per share.
●
Working Capital
Deficits – We had a working capital deficit of $69,512,829 at
December 31, 2017 compared to a working capital deficit of
$37,812,263 at December 31, 2016. Excluding long-term debt, we had
a working capital deficit of $29,968,427 at December 31, 2017,
compared to working capital of $5,599,927 at December 31, 2016. The
significant increase in working capital deficit between the periods
primarily related to the Final Arbitration Award and a decrease in
cash and cash equivalents.
●
Crude Supply Issues
– We currently have in place a month-to-month evergreen crude
supply contract with a major integrated oil and gas company. This
supplier currently provides us with adequate amounts of crude oil
and condensate, and we expect the supplier to continue to do so for
the foreseeable future. However, our ability to purchase
adequate amounts of crude oil and condensate is dependent on our
liquidity and access to capital, which have been adversely affected
by the contract-related dispute with GEL and other factors, as
noted above. The Final Arbitration Award could have a
material adverse effect on our ability to procure adequate amounts
of crude oil and condensate from our current supplier or
otherwise.
●
Financial Covenant
Defaults – In addition to existing events of default related
to the Final Arbitration Award, at December 31, 2017, LE and LRM
were in violation of certain financial covenants in secured loan
agreements with Veritex. Covenant defaults under the secured loan
agreements would permit Veritex to declare the amounts owed under
these loan agreements immediately due and payable, exercise its
rights with respect to collateral securing obligors’
obligations under these loan agreements, and/or exercise any other
rights and remedies available. The debt associated with these loans
was classified within the current portion of long-term debt on our
consolidated balance sheet at December 31, 2017 due to existing
events of default related to the Final Arbitration Award as well as
the uncertainty of LE and LRM’s ability to meet the financial
covenants in the future. There can be no assurance that Veritex
will provide a waiver of events of default related to the Final
Arbitration Award, consent to any proposed settlement with GEL or
provide future waivers of any financial covenant defaults, which
may have an adverse impact on our financial position and results of
operations.
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During the year
ended December 31, 2017, we continued aggressive actions to improve
operations and liquidity. We began selling certain of
our refined petroleum products immediately following production,
which minimizes inventory, improves cash flow, and reduces
commodity risk/exposure. We completed construction on several new
petroleum storage tanks at the Nixon Facility. Increased petroleum
storage capacity: (i) assists with de-bottlenecking the facility,
(ii) supports increased refinery throughput up to approximately
30,000 bpd, and (iii) provides an opportunity to generate
additional tank rental revenue by leasing to third-parties. We also
reduced our working capital requirements in a rising cost
environment by decreasing costs, reducing inventory levels,
improving our sales cycle, and requiring pre-payments from certain
customers. Management believes that it is taking the
appropriate steps to improve operations at the Nixon Facility and
our overall financial stability. However, there can be
no assurance that our business plan will be successful, LEH and its
affiliates will continue to fund our working capital needs, or that
we will be able to obtain additional financing on commercially
reasonable terms or at all. Among other factors, the
Final Arbitration Award could prevent us from successfully
executing our business plan.
For additional
disclosures related to the contract-related dispute with GEL, the
Final Arbitration Award, the GEL Letter Agreement (as amended),
defaults under secured loan agreements, and risk factors that could
materially affect our future business, financial condition and
results of operations, refer to the following sections in this
Annual Report:
●
Part I, Item 1A.
Risk Factors
●
Part I, Item 3.
Legal Proceedings
●
Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations:
-
GEL
Contract-Related Dispute and Final Arbitration
Award
-
Liquidity and
Capital Resources
●
Part II, Item 8.
Financial Statements and Supplementary Data, Notes to Consolidated
Financial Statements:
-
Note (8) Related
Party Transactions
-
Note (10) Long-Term
Debt, Net
-
Note (19)
Commitments and Contingencies – Legal
Matters
-
Note (20)
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, typically there
is a time lag between the comparable 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.
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Refinery Operations
Nixon
Facility
The Nixon Facility
is comprised of assets owned by LE and LRM. LE owns the
land, crude oil distillation unit, certain refined petroleum
product storage tanks and related piping, and loading and unloading
facilities and utilities. LRM owns the naphtha
stabilizer and depropanizer units, as well as certain petroleum
product storage tanks and related piping. Together, LE
and LRM own more than 1,000,000 bbls of crude oil, condensate, and
refined petroleum product storage capacity at the Nixon Facility.
Since 2015, the Nixon Facility has been undergoing a capital
improvement expansion project to construct over 800,000 bbls of
petroleum storage tankage. Increased petroleum storage
capacity: (i) assists with de-bottlenecking the facility, (ii)
supports increased refinery throughput up to approximately 30,000
bpd, and (iii) provides an opportunity to generate additional tank
rental revenue by leasing to third-parties. 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 (10) Long-Term Debt,
Net”.
A regional electric
cooperative supplies electrical power to the Nixon Facility. Fuel
gas that is produced at the Nixon Facility is 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 oil distillation unit, the first stage of the
crude oil refining process. The Nixon Facility’s current
level of complexity allows crude oil and condensate to be refined
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.
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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
Operation of the
Nixon Facility depends on our ability to purchase adequate amounts
of crude oil and condensate on favorable terms. We
currently have in place a month-to-month evergreen crude supply
contract with a major integrated oil and gas
company. This supplier currently provides us with
adequate amounts of crude oil and condensate, and we expect the
supplier to continue to do so for the foreseeable
future. However, our ability to purchase 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.
Management believes
that it is taking the appropriate steps to improve operations at
the Nixon Facility and our overall financial
stability. If our business plan is unsuccessful, it
could affect our ability to acquire adequate supplies of crude oil
and condensate under the existing contract or
otherwise. Among other factors, the Final Arbitration
Award could prevent us from successfully executing our business
plan and could have a material adverse effect on our ability to
procure adequate amounts of crude oil and condensate from our
current supplier or otherwise. Further, because our
existing crude supply contract is a month-to-month arrangement,
there can be no assurance that crude oil and condensate supplies
will continue to be available under this contract in the
future.
Products and Markets
Products
The Nixon
Facility’s product slate can be moderately adjusted based on
market demand. We currently produce a single finished product
– jet fuel. We produce several intermediate products,
including 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”). Our products
are primarily sold in the U.S. within PADD 3. However,
with the opening of the Mexican refined products market to private
companies, we occasionally sell refined products to customers that
export to Mexico. LEH, which is HUBZone certified, purchases our
jet fuel and resells the jet fuel to a government
agency. Our intermediate products are primarily sold in
nearby markets to wholesalers and refiners as a feedstock for
further blending and processing. (See “Part I,
Item 1. Business – Management” and “Part II, Item
8. Financial Statements and Supplementary Data – Note (8)
Related Party Transactions, Note (10) Long-Term Debt, Net, and Note
(19) Commitments and Contingencies – Financing
Agreements” for additional disclosures related to
LEH.)
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
one-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 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.
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Competition
Many of our
competitors are substantially larger than us and are engaged on a
national or international basis in many segments of the petroleum
products business, including exploration and production, refining,
transportation and marketing. These competitors may have greater
flexibility in responding to or absorbing market changes occurring
in one or more of these business segments. We compete primarily
based on cost. Due to the low complexity of our simple
“topping unit” refinery, we can be relatively nimble in
adjusting our refined petroleum products slate because of changing
commodity prices, market demand, and refinery operating
costs.
Business Strategy
Our overall
business strategy is to improve operations, increase refinery
throughput, improve refining margins, and continue the safe and
reliable operation of the Nixon Facility. Successful
execution of our business strategy depends on several key factors,
including reaching an acceptable settlement with GEL, having
adequate crude oil and condensate supplies and continuing to meet
contractual obligations.
Nixon
Facility Capital and Efficiency Improvements
In 2015, LE and LRM
secured $35.0 million in the aggregate in 19-year financing to
expand the Nixon Facility. Since 2015, the Nixon Facility has been
undergoing a capital improvement expansion project to construct
over 800,000 bbls of petroleum storage tankage. At December
31, 2017, the refinery had more than 1,000,000 bbls of crude oil,
condensate, and refined petroleum product storage capacity in 27
tanks. 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
bpd; (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.
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.
Improved
Financial Stability
As noted elsewhere
in this Annual Report, we began selling certain of our refined
petroleum products immediately following production, which
minimizes inventory, improves cash flow, and reduces commodity
risk/exposure. We also reduced our working capital
requirements in a rising cost environment by decreasing costs,
reducing inventory levels, improving our sales cycle, and receiving
pre-payments from certain customers. Management believes
that these efforts, combined with favorable margins, will improve
operations and liquidity. (See “Part I, Item 1.
Business – Going Concern” for certain factors that
raise substantial doubt about our ability to continue as a going
concern.)
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. We derived no
revenue from our Pipeline Transportation operations for the year
ended December 31, 2017. Our pipeline transportation
operations represented less than 1% of total revenue for the year
ended December 31, 2016.
We fully impaired
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, 2017 and
2016. All leases associated with our oil and gas properties have
expired, and our oil and gas properties were fully impaired in
2011.
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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 was dissolved in
March 2018.
Insurance and Risk Management
Our operations are
subject to significant hazards and risks inherent in crude oil and
condensate refining operations, as well as in the transportation
and storage of crude oil and condensate and finished and
intermediate petroleum products. We have property damage and
business interruption coverage at the Nixon Facility. Business
interruption coverage is for 24 months from the date of the loss,
subject to a deductible with a 45-day waiting period. Our property
damage insurance has deductibles ranging from $5,000 to $500,000.
In addition, we have a full suite of insurance policies covering
workers’ compensation, general liability, directors’
and officers’ liability, environmental liability, and other
business risks. These are supported by safety and other risk
management programs. See also, “Part I, Item 1A. Risk Factors
– Risks Related to Our Business” in this Annual
Report.
Governmental Regulation
Our operations and
properties are subject to extensive and complex federal, state, and
local environmental, health, and safety statutes, regulations, and
ordinances. These rules govern, among other things, the
generation, storage, handling, use and transportation of petroleum,
solid wastes, hazardous wastes, and hazardous substances; the
emission and discharge of materials into the environment and
environmental protection; waste management; characteristics and
composition of diesel and other fuels; and the monitoring,
reporting and control of greenhouse gas emissions. These laws
impose costly obligations on our operations, including requiring
the acquisition of permits and authorizations to conduct regulated
activities, restricting the way regulated activities are conducted,
limiting the quantities and types of materials that may be released
into the environment, and requiring the monitoring of releases of
materials into the environment.
Failure to comply
with environmental, health or safety laws and our existing permits
or other authorizations issued under such laws could result in
fines, civil or criminal penalties or other sanctions, injunctive
relief compelling the installation of additional controls, a
revocation of our permits, and/or the shutdown of our
facilities.
We cannot predict
the extent to which additional environmental, health, and safety
laws will be enacted in the future, or how existing or future laws
will be interpreted with respect to our operations. Many
environmental, health, and safety laws and regulations are becoming
increasingly stringent. The cost of compliance with and
governmental enforcement of environmental, health, and safety laws
may increase in the future. We may be required to make significant
capital expenditures or incur increased operating costs to achieve
or sustain compliance with applicable environmental, health, and
safety laws. This Governmental Regulation section should
be read in conjunction with “Part I, Item 1A. Risk
Factors” of this Annual Report, which discusses our
expectations regarding future events based on currently available
information.
Air
Emissions
Toxic Air
Pollutants
. The federal Clean Air Act (the
“CAA”)
is
a comprehensive law that regulates toxic air pollutants from
stationary and mobile sources. Among other things, the law
authorizes the Environmental Protection Agency (the
“EPA”) to establish National Ambient Air Quality
Standards to protect public health and public welfare and to
regulate emissions of hazardous air pollutants. The CAA, as well as
corresponding state laws and regulations regarding emissions of
pollutants into the air, affect our crude oil and condensate
processing operations and impact certain emissions sources located
offshore. Under the CAA, facilities that emit volatile organic
compounds (“VOCs”) or nitrogen oxides face increasingly
stringent regulations.
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Refineries, which
are major stationary sources of hazardous air pollutants, have
historically been high-visibility targets for enforcement by the
EPA under the CAA. Petroleum refineries are subject to
the EPA’s National Standards for Hazardous Air Pollutants.
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.
Under the
EPA’s Mobile Source Air Toxics regulations most refineries
are required to produce transportation fuels for highway use at or
below 15 ppm sulfur for “on-road” and
“off-road” diesel and 30 ppm sulfur for gasoline. The
Nixon Facility does not produce gasoline, and the facility ceased
production of nonroad, locomotive, and marine, a
transportation-related diesel fuel product in 2014 – when the
new regulations took effect. Since 2014, the Nixon
Facility has produced HOBM, a non-transportation lubricant blend
product. “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
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 sulfur control standards: (i)
in the U.S. as a feedstock to other refineries and blenders and
(ii) to other countries as a finished petroleum
product.
The EPA issued
three (3) final rules to cut emissions of methane from the oil and
gas industry. These final rules 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 an Information Collection Request
(“ICR”) to operators in the oil and natural gas
industry to obtain extensive information for developing regulations
to reduce methane emissions from existing oil and gas sources.
In March
2017, the EPA withdrew the ICR
request, effectively
immediately. As a result, responses to the ICR were no
longer required.
Greenhouse Gas Emissions
.
Emission of Greenhouse Gases (“GHGs”) is regulated by
the EPA under the CAA. 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 and Title V permitting requirements under the CAA
(the “CAA Permitting Requirements”).
The EPA established
GHG emissions thresholds to define when permits under the CAA
Permitting Requirements are required for new and existing
industrial facilities (the “Tailoring Rule”). Emissions
from small farms, restaurants, and all but the very largest
commercial facilities are not covered by the Tailoring Rule. The
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 Tailoring Rule in phases.
In 2016, the EPA
updated New Source Performance Standards 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 – would have created a
burden on the Nixon Facility related to its nonroad, locomotive,
and marine production through 2014, LE applied for an extension of
the temporary exemption afforded small refineries through December
31, 2010 under the CAA Section 211(o)(9)(B). The EPA
granted the Nixon Facility a small refinery exemption from RFS
requirements for 2013 and 2014. In 2014, the Nixon
Facility began producing HOBM, a non-transportation lubricant blend
product that does not fall under RFS.
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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 were not
threatened, and no further reporting was required.
Water
Discharges
Stormwater from the
Nixon Facility is tested and discharged pursuant to applicable
stormwater permits. Process wastewater from the Nixon
Facility is tested and discharged to a nearby municipal treatment
facility pursuant to applicable process wastewater permits.
Wastewater from our offshore facilities, including our oil and
natural gas pipelines and anchor platform, are tested and
discharged pursuant to applicable produced water
permits.
Spill
Prevention and Control
The 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. Waters that are
specifically excluded from the EPA’s jurisdiction include,
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.
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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.
The BSEE has partnered with the U.S. Coast Guard for oil spill
response. 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,
combined 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.
The BOEM has
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 amount
required for certain types of offshore facilities located seaward
of the seaward boundary of a state, including properties used for
oil transportation, is $35 million. BDPL currently maintains 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.
Under a newer
financial assurance program model, the BOEM no longer: (i) grants
waivers from additional security obligations and (ii) considers the
combined strength and reliability of co-lessees when determining a
lessee’s additional security requirements. Also,
provided 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 requested
that BDPL provide additional supplemental bonds or acceptable
financial assurance of approximately $4.6 million related to five
(5) existing pipeline rights-of-way. At December 31, 2017 and 2016,
BDPL maintained approximately $0.9 million in credit and
cash-backed pipeline rights-of-way bonds issued to the
BOEM. Of the five (5) existing pipeline rights-of-ways
related to BOEM’s request, the pipeline associated with one
(1) right-of-way was decommissioned in 1997. The BSEE approved BDPL
permit requests to decommission in place the pipelines for three
(3) of these rights-of-way. As a result, management is
seeking a reduction in the amount of BOEM’s request for
additional financial assurance. 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 BDPL is 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.
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Offshore
Safety
. Under the Workplace Safety Rule, BSEE
requires operators to employ a comprehensive safety and
environmental management system
(“SEMS”). SEMS and a subsequent revision to
SEMS (“SEMS II”) 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. BDPL has 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 and the National Emphasis Program for Petroleum
Refineries (the “RNEP”). RNEP requires
refineries to be inspected for compliance with process safety
management regulations. 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, LE
was assessed a civil penalty of $38,500. Following the 2016
inspection, LE was 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.
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 Amended and Restated 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
personnel services under the Amended and Restated Operating
Agreement:
●
Personnel serving
in the capacities of corporate executive officers, including Chief
Executive Officer and Chief Financial Officer, as well as general
manager, operations, maintenance, environmental, and health and
safety personnel; and
●
Personnel providing
administrative and professional services, including accounting,
human resources, insurance, and regulatory
compliance.
All personnel work
for and are paid by LEH. Blue Dolphin is billed by LEH
at cost plus a 5% markup. 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.
ITEM
1A. RISK FACTORS
An investment in our Common Stock involves risks. In addition to
the other information in this Annual Report and our other filings
with the SEC, you should carefully consider the following risk
factors in evaluating us and our business. The risks described
below are not the only risks we face. Additional risks and
uncertainties not specified herein, not currently known to us, or
currently deemed to be immaterial may also materially adversely
affect our business, financial condition, operating results and/or
cash flows.
Any one of these
factors or a combination of these factors could materially affect
our future results of operations and could influence whether any
forward-looking statements ultimately prove to be accurate. Our
forward-looking statements are not guarantees of future
performance, and actual results and future performance may differ
materially from those suggested in any forward-looking statements.
We do not intend to update these statements unless we are required
to do so.
Risks Related to Our Business and Industry
The adverse outcome in the arbitration of the contract-related
dispute with GEL had a material adverse effect on our business,
financial condition, and results of operations and could materially
adversely affect the value of an investment in our common
stock.
As previously
disclosed, LE was involved in the GEL Arbitration with GEL, an
affiliate of Genesis, related to a contractual dispute involving
the Crude Supply Agreement and the Joint Marketing
Agreement. On August 11, 2017, the arbitrator delivered
the Final Arbitration Award. The Final Arbitration Award
denied all LE’s claims against GEL and granted substantially
all the relief requested by GEL in its
counterclaims. Among other matters, the Final
Arbitration Award awarded damages and GEL’s attorneys’
fees and related expenses to GEL in the aggregate amount of
approximately $31.3 million.
As previously
disclosed, a hearing on confirmation of the Final Arbitration Award
was scheduled to occur on September 18, 2017 in state district
court in Harris County, Texas. Prior to the scheduled hearing, LE
and GEL jointly notified the court that the hearing would be
continued for the Continuance Period to facilitate settlement
discussions between the parties. On September 26, 2017, LE and Blue
Dolphin, together with LEH and Jonathan Carroll, entered into the
GEL Letter Agreement, effective September 18, 2017, confirming the
parties’ agreement to the continuation of the confirmation
hearing during the Continuance Period, subject to the terms of the
GEL Letter Agreement.
The GEL Letter
Agreement has been amended to extend the Continuance Period through
April 30, 2018. The GEL Letter Agreement, as amended to
date, prohibits Blue Dolphin and its affiliates from making any
pre-payments on indebtedness, other than in the ordinary course of
business as described in the GEL Letter Agreement, and from making
any payments to Jonathan Carroll under the Amended and Restated
Guaranty Fee Agreements between November 1, 2017 and the end of the
Continuance Period. (Jonathan Carroll has received no
cash payments since August 2016 and no common stock payments since
May 2017 under the Amended and Restated Guaranty Fee
Agreements.) If the parties are unable to reach an
acceptable settlement with Genesis and GEL, and GEL seeks to
confirm and enforce the Final Arbitration Award, our business,
financial condition, and results of operations will be materially
affected, and LE would likely be required to seek protection under
bankruptcy laws.
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Veritex notified
obligors that the Final Arbitration Award constitutes an event of
default under secured loan agreements with Veritex. The
occurrence of events of default under the secured loan agreements
permits Veritex 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. Veritex informed obligors that it is not currently
exercising its rights, privileges and remedies under the secured
loan agreements considering the ongoing settlement discussions with
GEL and the continuance of the hearing on confirmation of the Final
Arbitration Award and to allow Veritex to evaluate any proposed
settlement agreement related to the Final Arbitration Award, which
would require Veritex’s approval. However, Veritex expressly
reserved all its rights, privileges and remedies related to events
of default under the secured loan agreements and informed obligors
that it would consider a final confirmation of the Final
Arbitration Award to be a material event of default under the loan
agreements.
We can provide no
assurance as to whether negotiations with GEL will result in a
settlement, as to potential terms of any such settlement, whether
Veritex would approve of any such settlement, or whether Veritex
will exercise its rights and remedies under secured loan
agreements. If: (i) we are unable to reach an acceptable settlement
with GEL or Veritex does not approve any such settlement, (ii) GEL
seeks to confirm and enforce the Final Arbitration Award, or (iii)
Veritex exercises its rights and remedies under the secured loan
agreements, our business, financial condition, and results of
operations will be materially adversely affected, and LE would
likely be required to seek protection under bankruptcy
laws. In addition, our ability to procure adequate
amounts of crude oil and condensate and our relationships with our
customers could materially and adversely be affected, and the
trading prices of our common stock and the value of an investment
in our common stock could significantly decrease, which could lead
to holders of our common stock losing their investment in our
common stock in its entirety.
For additional
information regarding the Final Arbitration Award, the GEL Letter
Agreement (as amended), and their potential effects on our
business, financial condition, and results of operations, see
“Part I, Item 3. Legal Proceedings,” Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations,” and the notes to our consolidated
financial statements in “Part II, Item 8. Financial
Statements and Supplementary Data.”
We may not have sufficient liquidity to sustain operations because
of net losses, working capital deficits, and other factors,
including the Final Arbitration Award, crude supply issues, and
financial covenant defaults in secured loan
agreements.
For the year ended
December 31, 2017, we reported a net loss of $22,328,390, or a loss
of $2.09 per share, compared to a net loss of $15,767,448, or a
loss of $1.51 per share, for the year ended December 31,
2016. The $0.58 per share increase in net loss between
the periods was the result of the Final Arbitration Award, which
was partially offset by improved margins for refined petroleum
products and increased sales volume. The amount expensed
in the period related to the Final Arbitration Award was
$24,338,628, which represented $2.28 per
share. Excluding the Final Arbitration Award, we would
have reported net income of $0.19 per share.
We had a working
capital deficit of $69,512,829 at December 31, 2017 compared to a
working capital deficit of $37,812,263 at December 31, 2016.
Excluding long-term debt, we had a working capital deficit of
$29,968,427 at December 31, 2017, compared to working capital of
$5,599,927 at December 31, 2016. The significant increase in
working capital deficit between the periods primarily related to
the Final Arbitration Award and a decrease in cash and cash
equivalents.
We had cash and
cash equivalents and restricted cash (current portion) of $495,296
and $48,980, respectively, at December 31,
2017. Comparatively, we had cash and cash equivalents
and restricted cash (current portion) of $1,152,628 and $3,347,835,
respectively, at December 31, 2016.
The Final
Arbitration Award awarded damages and GEL’s attorneys’
fees and related expenses to GEL in the aggregate amount of
approximately $31.3 million. We can provide no assurance
as to whether negotiations with GEL will result in a settlement, as
to potential terms of any such settlement, whether Veritex would
approve of any such settlement, or whether Veritex will exercise
its rights and remedies under secured loan agreements. If: (i) we
are unable to reach an acceptable settlement with GEL or Veritex
does not approve any such settlement, (ii) GEL seeks to confirm and
enforce the Final Arbitration Award, or (iii) Veritex exercises its
rights and remedies under the secured loan agreements, our
business, financial condition, and results of operations will be
materially adversely affected, and LE would likely be required to
seek protection under bankruptcy laws.
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Following the
cessation of crude supplies under the Crude Supply Agreement with
GEL, we put in place a month-to-month evergreen crude supply
contract with a major integrated oil and gas
company. This supplier currently provides us with
adequate amounts of crude oil and condensate and having crude
supply continuity has boosted our customers’ confidence in
our performance ability and enabled us to slowly rebuild
counter-party relationships. However, we are currently
evaluating the effects of the Final Arbitration Award on our
business, financial condition, and results of
operations. In addition to the matters described above,
the Final Arbitration Award could materially and adversely affect
our ability to procure adequate amounts of crude oil and condensate
and our relationships with our customers.
As described
elsewhere in this Annual Report, Veritex notified obligors that the
Final Arbitration Award constitutes an event of default under
secured loan agreements with Veritex. (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
Veritex.)
Currently, we rely
on revenue from operations, LEH and its affiliates (including
Jonathan Carroll), and borrowings under bank facilities to meet our
liquidity needs. During the year ended December 31, 2017, we
continued aggressive actions to improve operations and liquidity.
We began selling certain of our refined petroleum products
immediately following production, which minimizes inventory,
improves cash flow, and reduces commodity risk/exposure. We
completed construction on several new petroleum storage tanks at
the Nixon Facility. Increased petroleum storage capacity: (i)
assists with de-bottlenecking the facility, (ii) supports increased
refinery throughput up to approximately 30,000 bpd, and (iii)
provides an opportunity to generate additional tank rental revenue
by leasing to third-parties. We also reduced our working capital
requirements in a rising cost environment by decreasing costs,
reducing inventory levels, improving our sales cycle, and requiring
pre-payments from certain customers. Management believes
that it is taking the appropriate steps to improve operations at
the Nixon Facility and our overall financial stability. However,
there can be no assurance that our business plan will be
successful, LEH and its affiliates will continue to fund our
working capital needs, or that we will be able to obtain additional
financing on commercially reasonable terms or at
all. Among other factors, the Final Arbitration Award
could prevent us from successfully executing our business
plan.
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 relating to 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.
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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 product produced. 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 our feedstocks from a single
supplier. Because of their integrated operations and
larger capitalization, larger, more complex refineries may be more
flexible in responding to volatile industry or market conditions,
such as crude oil and other feedstocks supply shortages or
commodity price fluctuations. If we are unable to
compete effectively, we may lose existing customers or fail to
acquire new customers.
Environmental laws and regulations could require us to make
substantial capital expenditures to remain in compliance or to
remediate current or future contamination that could give rise to
material liabilities.
Our operations are
subject to a variety of federal, state and local environmental laws
and regulations relating to the protection of the environment,
including those governing the emission or discharge of pollutants
into the environment, product specifications and the generation,
treatment, storage, transportation, disposal and remediation of
solid and hazardous wastes. Violations of these laws and
regulations or permit conditions can result in substantial
penalties, injunctive orders compelling installation of additional
controls, civil and criminal sanctions, permit revocations and/or
facility shutdowns.
In addition, new
environmental laws and regulations, new interpretations of existing
laws and regulations, increased governmental enforcement of laws
and regulations, or other developments could require us to make
additional unforeseen expenditures. Many of these laws and
regulations are becoming increasingly stringent, and the cost of
compliance with these requirements can be expected to increase over
time. The requirements to be met, as well as the technology and
length of time available to meet those requirements, continue to
develop and change. Expenditures or costs for environmental
compliance could have a material adverse effect on our results of
operations, financial condition, and profitability.
The Nixon Facility
operates under several federal and state permits, licenses, and
approvals with terms and conditions that contain a significant
number of prescriptive limits and performance standards. These
permits, licenses, approvals, limits, and standards require a
significant amount of monitoring, record keeping and reporting to
demonstrate compliance with the underlying permit, license,
approval, limit or standard. Non-compliance or incomplete
documentation of our compliance status may result in the imposition
of fines, penalties and injunctive relief. Additionally, there may
be times when we are unable to meet the standards and terms and
conditions of our permits, licenses and approvals due to
operational upsets or malfunctions, which may lead to the
imposition of fines and penalties or operating restrictions that
may have a material adverse effect on our ability to operate our
facilities, and accordingly our financial performance.
We are subject to strict laws and regulations regarding personnel
and process safety, and failure to comply with these laws and
regulations could have a material adverse effect on our results of
operations, financial condition and profitability.
We are subject to
the requirements of OSHA and comparable state statutes that
regulate the protection of the health and safety of workers, and
the proper design, operation and maintenance of our equipment. In
addition, OSHA and certain environmental regulations require that
we maintain information about hazardous materials used or produced
in our operations and that we provide this information to personnel
and state and local governmental authorities. Failure to comply
with these requirements, including general industry standards,
record keeping requirements and monitoring and control of
occupational exposure to regulated substances, may result in
significant fines or compliance costs, which could have a material
adverse effect on our results of operations, financial condition
and cash flows.
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Our insurance policies may be inadequate or expensive.
Our insurance
coverage does not cover all potential losses, costs or liabilities.
We could suffer losses for uninsurable or uninsured risks or in
amounts more than our existing insurance coverage. Our ability to
obtain and maintain adequate insurance may be affected by
conditions in the insurance market over which we have no control.
In addition, if we experience insurable events, we may experience
an increase in annual premiums, a limit on coverage, or loss of
coverage. Inadequate insurance or loss of coverage could
have a material adverse effect on our business, financial
condition, and results of operations.
LEH holds a significant interest in us, and our related party
transactions with LEH and its affiliates may cause conflicts of
interest that may adversely affect us.
Jonathan Carroll,
our Chief Executive Officer, President, Assistant Treasurer and
Secretary, is also a majority owner of LEH. Together LEH and
Jonathan Carroll own 80.2% of our Common Stock, and, pursuant to
the Amended and Restated Operating Agreement, manages and operates
all Blue Dolphin properties. LEH and Jonathan Carroll
have significant influence over matters such as the election of the
Board, control over our business, policies and affairs and other
matters submitted to our stockholders. LEH and Jonathan 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.
Defaults under our secured loan agreements could have a material
adverse effect on our business, financial condition, and results of
operations and materially adversely affect the value of an
investment in our common stock.
As described
elsewhere in this Annual Report, Veritex notified obligors that the
Final Arbitration Award constitutes an event of default under
secured loan agreements with Veritex. In addition to
existing events of default related to the Final Arbitration Award,
at December 31, 2017, LE and LRM were in violation of the debt
service coverage ratio, the current ratio, and debt to net worth
ratio financial covenants related to the secured loan
agreements. LE also failed to replenish a payment
reserve account as required. The occurrence of events of
default under the secured loan agreements permits Veritex to
declare the amounts owed under the secured loan agreements
immediately due and payable, exercise its rights with respect to
collateral securing obligors’ obligations under the loan
agreements, and/or exercise any other rights and remedies
available. Veritex informed obligors that it is not
currently exercising its rights, privileges and remedies under the
secured loan agreements considering the ongoing settlement
discussions with GEL and the continuance of the hearing on
confirmation of the Final Arbitration Award and to allow Veritex to
evaluate any proposed settlement agreement related to the Final
Arbitration Award, which would require Veritex’s
approval. However, Veritex expressly reserved all its
rights, privileges and remedies related to events of default under
the secured loan agreements and informed obligors that it would
consider a final confirmation of the Final Arbitration Award to be
a material event of default under the loan
agreements. Any exercise by Veritex of its rights and
remedies under the secured loan agreements would have a material
adverse effect on our business, financial condition, and results of
operations and would likely require us to seek protection under
bankruptcy laws.
There can be no
assurance that: (i) our assets or cash flow would be sufficient to
fully repay borrowings under outstanding long-term debt, either
upon maturity or if accelerated, (ii) LE and LRM would be able to
refinance or restructure the payments on the long-term debt, and/or
(iii) Veritex will provide future waivers. Defaults under secured
loan agreements and any exercise by Veritex of its rights and
remedies related to such defaults may have a material adverse
effect on the trading prices of our common stock and on the value
of an investment in our common stock, and holders of our common
stock could lose their investment in our common stock in its
entirety, particularly if LE is required to seek bankruptcy
protection because of the exercise by Veritex of such rights and
remedies.
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For additional
information regarding defaults under our secured loan agreements
and their potential effects on our business, financial condition,
and results of operations, see “Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations” and “Part II and the notes
to our financial statements in “Part II, Item 8. Financial
Statements and Supplementary Data.”
Our ability to use net operating loss (“NOL”)
carryforwards to offset future taxable income for U.S. federal
income tax purposes is subject to limitation.
Under Section 382
of the Internal Revenue Code of 1986, as amended (“IRC
Section 382”), a corporation that undergoes an
“ownership change” is subject to limitations on its
ability to utilize its pre-change NOL carryforwards to offset
future taxable income. Within the meaning of IRC Section 382, an
“ownership change” occurs when the aggregate stock
ownership of certain stockholders (generally 5% shareholders,
applying certain look-through rules) increases by more than 50
percentage points over such stockholders' lowest percentage
ownership during the testing period (generally three
years).
Blue Dolphin
experienced ownership changes in 2005 because of 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,
2017 and 2016, management determined that cumulative losses
incurred over the prior three-year period provided significant
objective evidence that limited the ability to consider other
subjective evidence, such as projections for future growth. Based
on this evaluation, we recorded a full valuation allowance against
the deferred tax assets as of December 31, 2017 and
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.
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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, 2017, that conditions exist that raise
substantial doubt about our ability to continue as a going concern
due to the Final Arbitration Award, defaults in secured loan
agreements, 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 reaching a
settlement agreement with GEL related to the Final Arbitration
Award, sustained positive operating margins, and financing at
commercially reasonable terms for working capital to operate the
Nixon Facility, purchase crude oil and condensate, and fund capital
expenditures. If we are unable to achieve these goals, our
business would be jeopardized, and we may not be able to
continue.
Refining margins are volatile, and a reduction in refining margins
will adversely affect the amount of cash we will have available for
working capital.
Historically,
refining margins have been volatile, and they are likely to
continue to be volatile in the future. Our financial results are
primarily affected by the relationship, or margin, between our
refined petroleum product sales prices and our crude oil and
condensate costs. Our crude oil and condensate
acquisition costs and the prices at which we can ultimately sell
our refined petroleum products depend upon numerous factors beyond
our control. The prices at which we sell refined petroleum products
are strongly influenced by the commodity price of crude oil. If
crude oil prices increase, our “refinery operations”
business segment margins will fall unless we can pass along these
price increases to our wholesale customers. Increases in the
selling prices for refined petroleum products typically trail the
rising cost of crude oil and may be difficult to implement when
crude oil costs increase dramatically over a short
period.
The price volatility of crude oil, other feedstocks, refined
petroleum products, and fuel and utility services may have a
material adverse effect on our earnings, cash flows and
liquidity.
Our refining
earnings, cash flows and liquidity from operations depend primarily
on the margin above operating expenses (including the cost of
refinery feedstocks, such as crude oil and condensate that are
processed and blended into refined petroleum products) at which we
can sell refined petroleum products. Crude oil refining is
primarily a margin-based business. To improve margins, it is
important for a crude oil refinery to maximize the yields of high
value finished petroleum produces and to minimize the costs of
feedstocks and operating expenses. When the margin between refined
petroleum product prices and crude oil and other feedstock costs
decreases, our margins are negatively affected. Crude oil refining
margins have historically been volatile, and are likely to continue
to be volatile, because of a variety of factors, including
fluctuations in the prices of crude oil, other feedstocks, refined
petroleum products, and fuel and utility services. 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, typically there is a time lag between the comparable
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.;
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●
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
●
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. Following the cessation of
crude supplies under the Crude Supply Agreement with GEL, we put in
place a month-to-month evergreen crude supply contract with a major
integrated oil and gas company. This supplier currently
provides us with adequate amounts of crude oil and condensate and
having crude supply continuity has boosted our customers’
confidence in our performance ability and enabled us to slowly
rebuild counter-party relationships. However, we are
currently evaluating the effects of the Final Arbitration Award on
our business, financial condition, and results of
operations. In addition to the matters described above,
the Final Arbitration Award could materially and adversely affect
our ability to procure adequate amounts of crude oil and condensate
and our relationships with our customers.
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, 2017, the Nixon Facility operated for a total of 348
days, reflecting 17 days of refinery downtime. For the
year ended December 31, 2016, the Nixon Facility operated for a
total of 291 days, reflecting 75 days of refinery downtime. The
significant amount of refinery downtime during 2016 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 3. Legal
Proceedings” and “Part II, Item 8. Financial Statements
and Supplementary Data – Note (19) Commitments and
Contingencies – Legal Matters” for disclosures related
to the GEL contract-related dispute and Final Arbitration
Award.)
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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 and its affiliates (including
Jonathan Carroll) may, but are 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. Currently, we rely on revenue from
operations, including sales of refined petroleum products and
rental of petroleum storage tanks, LEH and its affiliates
(including Jonathan Carroll), and borrowings under bank facilities
to meet our liquidity needs. At December 31, 2017 and 2016,
accounts payable, related party was $974,400 and $369,600,
respectively.
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.
Our business may suffer if any of the executive officers or other
key personnel discontinue 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, 2017, we had 3 customers that accounted for
approximately 70% of our refined petroleum product
sales. LEH was 1 of these 3 significant customers and
accounted for approximately 33% of our refined petroleum product
sales. At December 31, 2017, these 3 customers
represented approximately $1.3 million in accounts
receivable. LEH represented approximately $0.7 million
in accounts receivable. LEH, which is HUBZone certified,
purchases our jet fuel and resells the jet fuel to a government
agency. (See “Part I, Item 1. Business –
Management” and “Part II, Item 8. Financial Statements
and Supplementary Data – Note (8) Related Party Transactions,
Note (10) Long-Term Debt, Net, and Note (19) Commitments and
Contingencies – Financing Agreements” for additional
disclosures related to LEH.)
For the year ended
December 31, 2016, we had 4 customers that accounted for
approximately 67% of our refined petroleum product
sales. LEH was one of these 4 significant customers and
accounted for approximately 27% of our refined petroleum product
sales. At December 31, 2016, these 4 customers represented
approximately $1.6 million in accounts receivable. LEH
represented approximately $1.6 million in accounts
receivable.
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.
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Additionally, our
profitability could be adversely affected if there is consolidation
among our customer base and our customers command increased
leverage in negotiating prices and other terms of sale. We could
decide not to sell our refined petroleum products to a certain
customer if, because of increased leverage, the customer pressures
us to reduce our pricing such that our gross profits are
diminished, which could result in a decrease in our revenue.
Consolidation may also lead to reduced demand for our products,
replacement of our products by the combined entity with those of
our competitors, and cancellations of orders, each of which could
harm our operating results.
The sale of refined petroleum products to the wholesale market is
our primary business, and if we fail to maintain and grow the
market share of our refined petroleum products, our operating
results could suffer.
Our success in the
wholesale market depends in large part on our ability to maintain
and grow our image and reputation as a reliable operator and to
expand into and gain market acceptance of our refined petroleum
products. Adverse perceptions of product quality, whether
justified, or allegations of product quality issues, even if false
or unfounded, could tarnish our reputation and cause our wholesale
customers to choose refined petroleum products offered by our
competitors.
We are dependent on third-parties for the transportation of crude
oil and condensate into and refined petroleum products out of our
Nixon Facility, and if these third-parties become unavailable to
us, our ability to process crude oil and condensate and sell
refined petroleum products to wholesale markets could be materially
and adversely affected.
We rely on trucks
for the receipt of crude oil and condensate into and the sale of
refined petroleum products out of our Nixon Facility. Since we do
not own or operate any of these trucks, their continuing operation
is not within our control. If any of the third-party trucking
companies that we use, or the trucking industry in general, become
unavailable to transport crude oil, condensate, and/or our refined
petroleum products because of acts of God, accidents, government
regulation, terrorism or other events, our revenue and net income
would be materially and adversely affected.
Our suppliers source a substantial amount, if not all, of our crude
oil and condensate from the Eagle Ford Shale and may experience
interruptions of supply from that region.
Our suppliers
source a substantial amount, if not all, of our crude oil and
condensate from the Eagle Ford Shale. Consequently, we may be
disproportionately exposed to the impact of delays or interruptions
of supply from that region caused by transportation capacity
constraints, curtailment of production, unavailability of
equipment, facilities, personnel or services, significant
governmental regulation, natural disasters, adverse weather
conditions, plant closures for scheduled maintenance or
interruption of transportation of oil or natural gas produced from
the wells in that area.
Our refining operations and customers are primarily located within
the Eagle Ford Shale and changes in the supply/demand balance in
this region could result in lower refining margins.
Our primary
operating asset, the Nixon Facility, is in the Eagle Ford Shale and
we market our refined petroleum products in a single, relatively
limited geographic area. Therefore, we are more susceptible to
regional economic conditions than our more geographically
diversified competitors. Should the supply/demand
balance shift in our region due to changes in the local economy, an
increase in refining capacity or other reasons, resulting in supply
in the PADD 3 (Gulf Coast) region to exceed demand, we would have
to deliver refined petroleum products to customers outside of our
current operating region and thus incur considerably higher
transportation costs, resulting in lower refining
margins.
Regulation of GHG 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 GHGs 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 GHG emissions are currently in
various stages of discussion and implementation. These and other
GHG 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 GHG 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.
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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.
The BOEM requested
that BDPL provide additional supplemental bonds or acceptable
financial assurance of approximately $4.6 million related to five
(5) existing pipeline rights-of-way. At December 31, 2017 and 2016,
BDPL maintained approximately $0.9 million in credit and
cash-backed pipeline rights-of-way bonds issued to the
BOEM. Of the five (5) existing pipeline rights-of-ways
related to BOEM’s request, the pipeline associated with one
(1) right-of-way was decommissioned in 1997. The BSEE approved BDPL
permit requests to decommission in place the pipelines for three
(3) of these rights-of-way. As a result, management is
seeking a reduction in the amount of BOEM’s request for
additional financial assurance. 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 BDPL is 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.
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.
The BOEM has
established 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. 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, 2017 and 2016, our estimated future
asset retirement obligations were approximately $2.3
million. See “Part II, Item 8. Financial
Statements and Supplementary Data – Note (11) Asset
Retirement Obligations” of this Annual Report for additional
information regarding asset retirement obligations.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
BLUE DOLPHIN ENERGY
COMPANY
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|
FORM 10-K
12/31/17
|
ITEM
2. PROPERTIES
LEH manages and
operates all Blue dolphin properties pursuant to the Amended and
Restated Operating Agreement. Management believes 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
|
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Owned /
Leased
|
|
Location
|
|
|
|
|
|
|
|
Refinery Operations
|
|
|
|
|
|
|
●
Nixon Facility (56
acres)
|
|
LE,
LRM
|
|
owned
|
|
Nixon,
Texas
|
|
|
|
|
|
|
|
Corporate and Other
|
|
|
|
|
|
|
●
Freeport Facility
(162 acres)
|
|
BDPL
|
|
owned
|
|
Freeport,
Texas
|
|
|
|
|
|
|
|
●
Pipelines and oil
and gas working interests in wells
|
|
BDPL,
BDPC
|
|
Owned and leasehold
interests
|
|
Gulf of
Mexico
|
|
|
|
|
|
|
|
●
Corporate
headquarters
|
|
BDSC
|
|
leased
|
|
Houston,
Texas
|
Nixon Facility
. See “Part
I, Item 1. Business – Company Overview and Refinery
Operations” for a description of the Nixon Facility. 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 (10) Long-Term Debt,
Net”.
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. In February 2017, BDPL sold approximately 15
acres of property located in Brazoria County, Texas to FLIQ Common
Facilities, LLC, an affiliate of FLNG.
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:
|
|
|
|
|
|
|
|
Pipeline
|
|
|
|
Blue Dolphin Pipeline
(1)
|
100
%
|
38
|
180
|
GA 350 Pipeline
(1)
|
100
%
|
13
|
65
|
Omega Pipeline
(2)
|
100
%
|
18
|
110
|
_____________________
(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
●
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.
BLUE DOLPHIN ENERGY
COMPANY
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|
FORM 10-K
12/31/17
|
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 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, 2017 and 2016, 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 7,675 square feet of office space in Houston, Texas. Our
office lease is discussed more fully in “Part II, Item 8.
Financial Statements and Supplementary Data – Note (15)
Leases” of this Annual Report.
ITEM
3. LEGAL PROCEEDINGS
GEL Contract-Related Dispute and Final Arbitration
Award
As previously
disclosed, LE was involved in the GEL Arbitration with GEL, an
affiliate of Genesis, related to a contractual dispute involving
the Crude Supply Agreement and the Joint Marketing Agreement, each
between LE and GEL and dated August 12, 2011. On August
11, 2017, the arbitrator delivered the Final Arbitration
Award. The Final Arbitration Award denied all LE’s
claims against GEL and granted substantially all the relief
requested by GEL in its counterclaims. Among other
matters, the Final Arbitration Award awarded damages and
GEL’s attorneys’ fees and related expenses to GEL in
the aggregate amount of approximately $31.3 million.
As previously
disclosed, a hearing on confirmation of the Final Arbitration Award
was scheduled to occur on September 18, 2017 in state district
court in Harris County, Texas. Prior to the scheduled hearing, LE
and GEL jointly notified the court that the hearing would be
continued for the Continuance Period to facilitate settlement
discussions between the parties. On September 26, 2017, LE and Blue
Dolphin, together with LEH and Jonathan Carroll, entered into the
GEL Letter Agreement, confirming the parties’ agreement to
the continuation of the confirmation hearing during the Continuance
Period, subject to the terms of the GEL Letter
Agreement.
The GEL Letter
Agreement has been amended to extend the Continuance Period through
April 30, 2018. The GEL Letter Agreement, as amended to
date, prohibits Blue Dolphin and its affiliates from making any
pre-payments on indebtedness, other than in the ordinary course of
business as described in the GEL Letter Agreement, and from making
any payments to Jonathan Carroll under the Amended and Restated
Guaranty Fee Agreements between November 1, 2017 and the end of the
Continuance Period. (Jonathan Carroll has received no
cash payments since August 2016 and no common stock payments since
May 2017 under the Amended and Restated Guaranty Fee
Agreements.) If the parties are unable to reach an
acceptable settlement with Genesis and GEL, and GEL seeks to
confirm and enforce the Final Arbitration Award against LE, our
business, financial condition, and results of operations will be
materially affected, and LE would likely be required to seek
protection under bankruptcy laws.
Other Legal Matters
From time to time
we are involved in routine lawsuits, claims, and proceedings
incidental to the conduct of our business, including
mechanic’s liens and administrative
proceedings. Management does not believe that such
matters will have a material adverse effect on our financial
position, earnings, or cash flows.
ITEM 4. MINE AND SAFETY DISCLOSURES
Not
applicable.
BLUE DOLPHIN ENERGY
COMPANY
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|
FORM 10-K
12/31/17
|