Notes to Consolidated Financial Statements
(1)
Organization
Nature of
Operations
. Blue Dolphin Energy Company
(“Blue Dolphin,”) is primarily an independent refiner
and marketer of petroleum products. Our primary asset is
a 15,000-bpd crude oil and condensate processing facility located
in Nixon, Texas (the “Nixon Facility”). As
part of our refinery business segment, we conduct petroleum storage
and terminaling operations under third-party lease agreements at
the Nixon Facility. We also own pipeline assets and have
leasehold interests in oil and gas properties. (See “Note (4)
Business Segment Information” for further discussion of our
business segments.)
Structure and
Management
.
Blue
Dolphin was formed as a Delaware corporation in 1986. We
are currently controlled by Lazarus Energy Holdings, LLC
(“LEH”). LEH operates and manages all our 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 approximately 81% of
our common stock, par value $0.01 per share (the “Common
Stock). (See “Note (8) Related Party Transactions,”
“Note (10) Long-Term Debt, Net” and “Note (18)
Commitments and Contingencies – Financing Agreements”
for additional disclosures related to LEH, the Amended and Restated
Operating Agreement, and Jonathan Carroll.)
Our operations are
conducted through the following active subsidiaries:
●
Lazarus Energy,
LLC, a Delaware limited liability company
(“LE”).
●
Lazarus Refining
& Marketing, LLC, a Delaware limited liability company
(“LRM”).
●
Blue Dolphin Pipe
Line Company (“BDPL”), a Delaware
corporation.
●
Blue Dolphin
Petroleum Company, a Delaware corporation.
●
Blue Dolphin
Services Co., a Texas corporation.
See "Part I, Item
1. Business and Item 2. Properties” in our Annual Report on
Form 10-K for the fiscal year ended December 31, 2016 (the
“Annual Report”) as filed with the Securities and
Exchange Commission (the “SEC”) for additional
information regarding our operating subsidiaries, principal
facilities, and assets.
References in this
Quarterly Report to “we,” “us,” and
“our” are to Blue Dolphin and its subsidiaries unless
otherwise indicated or the context otherwise requires.
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 of LE’s claims against GEL and
granted substantially all of the relief requested by GEL in its
counterclaims. Among other matters, the Final Arbitration Award
awarded damages, legal and administrative fees and court costs to
GEL in the aggregate amount of approximately $31.3
million.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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N
otes
to Consolidated Financial Statements
(Continued)
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.
Under
the GEL Letter Agreement, GEL could have terminated the GEL Letter
Agreement on the 45
th
day of the
Continuance Period, or November 1, 2017, if it determined, in its
sole discretion, that settlement discussions between the parties
were not advancing to an acceptable resolution. As previously
disclosed, on November 1, 2017, LE and GEL amended the GEL Letter
Agreement (the “Amended GEL Letter Agreement”) to
extend the date through which GEL has the right to terminate the
GEL Letter Agreement to November 28, 2017. The Amended GEL Letter
Agreement 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. 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 we likely would 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, has 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 has informed obligors that it is not currently
exercising its rights and remedies under the secured loan
agreements in light of 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 of its rights, privileges and remedies related to
events of default under the secured loan agreements and informed
obligors that it would consider a final confirmation of the Final
Arbitration Award to be a material event of default under the loan
agreements. 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 likely would 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 September 30, 2017 due to
existing or potential 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.
We can
provide no assurance as to whether negotiations with GEL will
result in a settlement or as to 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 we likely would be required to seek protection under
bankruptcy laws.
Operating
Risks
. Successful execution of our business plan
depends on several key factors, including having adequate crude oil
and condensate supplies, increasing sales of refined petroleum
products, and meeting contractual obligations. For the three and
nine months ended September 30, 2017, execution of our business
plan was negatively impacted by several factors,
including:
●
Net Losses –
We saw an improvement in net income for the three months ended
September 30, 2017. For the three months ended September
30, 2017, we reported net income of $3,945,519, or income of $0.36
per share, compared to a net loss of $1,938,551, or a loss of $0.19
per share, for the three months ended September 30,
2016. The $0.55 per share increase between the periods
was primarily the result of favorable refining margins in the
current three-month period. For the nine months ended
September 30, 2017, we reported a net loss of $23,297,713, or a
loss of $2.19 per share, compared to a net loss of $7,250,371, or a
loss of $0.69 per share, for the nine months ended September 30,
2016. The $1.50 per share increase in net loss between
the periods was primarily the result of the Final Arbitration
Award.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
●
Working Capital
Deficits – We had a working capital deficit of $67,084,694 at
September 30, 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 $27,328,649 at September 30, 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.
●
Termination of
Relationship with Genesis and GEL – As previously disclosed
and discussed elsewhere in this Quarterly Report, LE ceased
purchases of crude oil and condensate from GEL under the Crude
Supply Agreement in November 2016 and suspended the marketing and
sale of refined petroleum products under the Joint Marketing
Agreement following the processing of all crude oil and condensate
supplied by GEL.
●
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
new 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 or potential events of
default related to the Final Arbitration Award, at September 30,
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 September 30, 2017 due to
existing or potential 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.
During the nine
months ended September 30, 2017, we continued aggressive actions to
improve operations and liquidity. We began selling all
our jet fuel immediately following production, which minimizes
inventory, improves cash flow, and reduces commodity
risk/exposure. We also completed construction of several
new petroleum storage tanks at the Nixon Facility. Increasing
petroleum storage capacity: (i) assists with de-bottlenecking the
facility, (ii) supports increased refinery throughput up to
approximately 17,000 bpd, and (iii) provides an opportunity to
generate additional tank rental revenue by leasing to
third-parties. Additional ongoing efforts to improve
operations and liquidity include restructuring customer contracts
on more favorable terms as they come up for
renewal. Management believes that it is taking the
appropriate steps to improve our financial
stability. However, there can be no assurance that our
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 plan.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
For additional
disclosures related to the contract-related dispute with GEL, the
Final Arbitration Award, the GEL Letter Agreement, defaults under
secured loan agreements, and risk factors that could materially
affect our future business, financial condition and results of
operations, refer to the following sections within this Quarterly
Report:
●
Part I, Item 1.
Financial Statements, Notes to Consolidated Financial
Statements:
-
Note (8) Related
Party Transactions
-
Note (10) Long-Term
Debt, Net
-
Note (18)
Commitments and Contingencies –Legal
Matters
-
Note (19)
Subsequent Events
●
Part I, Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations:
-
GEL
Contract-Related Dispute and Final Arbitration
Award
-
Liquidity and
Capital Resources
●
Part II, Item 1.
Legal Proceedings
●
Part II, Item 1A.
Risk Factors
(2)
Basis of Presentation
The accompanying
unaudited consolidated financial statements, which include Blue
Dolphin and subsidiaries, have been prepared in accordance with
U.S. generally accepted accounting principles (“GAAP”)
for interim consolidated financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X.
Accordingly, certain information and footnote disclosures normally
included in our audited financial statements have been condensed or
omitted pursuant to the SEC’s rules and regulations.
Significant intercompany transactions have been eliminated in the
consolidation. In management’s opinion, all
adjustments considered necessary for a fair presentation have been
included, disclosures are adequate, and the presented information
is not misleading.
The consolidated
balance sheet as of December 31, 2016 was derived from the audited
financial statements at that date. The accompanying
consolidated financial statements should be read in conjunction
with the consolidated financial statements and notes thereto
included in our Annual Report. Operating results for the
three and nine months ended September 30, 2017 are not necessarily
indicative of the results that may be expected for the fiscal year
ending December 31, 2017, or for any other period.
(3)
Significant Accounting Policies
The summary of
significant accounting policies of Blue Dolphin is presented to
assist in understanding our consolidated financial statements. Our
consolidated financial statements and accompanying notes are
representations of management who is responsible for their
integrity and objectivity. These accounting policies conform to
GAAP and have been consistently applied in the preparation of our
consolidated financial statements.
Use of Estimates
.
We have made several estimates and
assumptions related to the reporting of our consolidated assets and
liabilities and to the disclosure of contingent assets and
liabilities to prepare these consolidated financial statements in
conformity with GAAP. We believe our current estimates are
reasonable and appropriate, however, actual results could differ
from those estimated.
Cash and Cash
Equivalents
.
Cash and cash equivalents
represent liquid investments with an original maturity of three
months or less. Cash balances are maintained in depository and
overnight investment accounts with financial institutions that, at
times, may exceed insured deposit limits. We monitor the financial
condition of the financial institutions and have experienced no
losses associated with these accounts. Cash and cash
equivalents were $44,931 at September 30, 2017 compared to cash and
cash equivalents of $1,152,628 at December 31, 2016.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
Restricted Cash
.
Restricted cash (current portion)
primarily represents: (i) amounts held in our disbursement account
with Veritex attributable to construction invoices awaiting payment
from that account, (ii) a payment reserve account held by Veritex
as security for payments under a loan agreement, and (iii) a
construction contingency account under which Veritex will fund
contingencies. Restricted cash, noncurrent represents
funds held in the Veritex disbursement account for payment of
future construction related expenses to build new petroleum storage
tanks. At September 30, 2017, total restricted cash was $1,650,910,
comprised of restricted cash (current portion) totaling $1,500,380
and restricted cash, noncurrent totaling $150,530. At
December 31, 2016, total restricted cash was $4,930,140, comprised
of restricted cash (current portion) totaling $3,347,835 and
restricted cash, noncurrent totaling $1,582,305
(See “Note (10) Long-Term
Debt, Net” for additional disclosures related to our loan
agreements with Veritex.)
Accounts Receivable and Allowance for
Doubtful Accounts
.
Our accounts receivable consists
of customer obligations due in the ordinary course of
business. Since we have a small number of customers with
individually large amounts due on any given date, we evaluate
potential and existing customers’ financial condition, credit
worthiness, and payment history to minimize credit risk. Allowance
for doubtful accounts is based on a combination of current sales
and specific identification methods. If necessary, we establish an
allowance for doubtful accounts to estimate the amount of probable
credit losses. Allowance for doubtful accounts totaled
$0 both at September 30, 2017 and December 31, 2016.
Inventory
.
Our inventory primarily consists
of refined petroleum products, crude oil and condensate, and
chemicals. Inventory is valued at lower of cost or net
realizable value with cost being determined by the average cost
method, and net realizable value being determined based on
estimated selling prices less any associated delivery
costs. If the net realizable value of our refined
petroleum products inventory declines to an amount less than our
average cost, we record a write-down of inventory and an associated
adjustment to cost of refined products sold. (See
“Note (6) Inventory” for additional disclosures related
to our inventory.)
Property and
Equipment
.
Refinery and Facilities
. Management
expects to continue making improvements to the Nixon Facility based
on operational needs and technological
advances. Additions to refinery and facilities assets
are capitalized. Expenditures for repairs and maintenance are
expensed as incurred and included as operating expenses under the
Amended and Restated Operating Agreement.
We record refinery
and facilities at cost less any adjustments for depreciation or
impairment. Adjustment of the asset and the related
accumulated depreciation accounts are made for the refinery and
facilities asset’s retirement and disposal, with the
resulting gain or loss included in the consolidated statements of
operations. For financial reporting purposes,
depreciation of refinery and facilities assets is computed using
the straight-line method using an estimated useful life of 25 years
beginning when the refinery and facilities assets are placed in
service. We did not record any impairment of our
refinery and facilities assets for any period
presented.
Pipelines and Facilities
. Our pipelines
and facilities are recorded at cost less any adjustments for
depreciation or impairment. Depreciation is computed
using the straight-line method over estimated useful lives ranging
from 10 to 22 years. In accordance with Financial Accounting
Standards Board (“FASB”) ASC guidance on accounting for
the impairment or disposal of long-lived assets, management
performed periodic impairment testing of our pipeline and
facilities assets in the fourth quarter of 2016. Upon completion of
that testing, our pipeline assets were fully
impaired. 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.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
Oil and Gas Properties
. Our oil and gas
properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition,
exploration and development of oil and gas properties, including
directly related internal costs, are capitalized on a cost center
basis. Amortization of such costs and estimated future
development costs are determined using the unit-of-production
method. All leases associated with our oil and gas properties have
expired, and our oil and gas properties were fully impaired in
2011.
Construction in Progress
. Construction
in progress expenditures, which relate to construction and
refurbishment activities at the Nixon Facility, are capitalized as
incurred. Depreciation begins once the asset is placed in
service.
(See “Note
(7) Property, Plant and Equipment, Net” for additional
disclosures related to our refinery and facilities assets, oil and
gas properties, pipelines and facilities assets, and construction
in progress.)
Intangibles – Other
.
Trade name, an intangible asset, represents the “Blue Dolphin
Energy Company” brand name. At September 30, 2017
and December 31, 2016, trade name totaled $303,346. We have
determined the trade name to have an indefinite useful life. We
account for other intangible assets under FASB ASC guidance related
to intangibles, goodwill, and other. Under the guidance, we test
intangible assets with indefinite lives annually for impairment.
Management performed its regular annual impairment testing of trade
name in the fourth quarter of 2016. Upon completion of that
testing, we determined that no impairment was necessary at December
31, 2016.
Debt Issue Costs
. We have debt
issue costs related to certain refinery and facilities assets debt.
Debt issue costs are capitalized and amortized over the term of the
related debt using the straight-line method, which approximates the
effective interest method. Debt issue costs are presented net with
the related debt liability. (See “Note (10)
Long-Term Debt, Net” for additional disclosures related to
debt issue costs.)
Revenue
Recognition
.
Refined Petroleum Products Revenue
.
Revenue from the sale of refined petroleum products is recognized
when sales prices are fixed or determinable, collectability is
reasonably assured, and title passes. Title passage occurs when
refined petroleum products are delivered in accordance with the
terms of the respective sales agreements, and customers assume the
risk of loss when title is transferred. Transportation, shipping,
and handling costs incurred are included in cost of refined
products sold. Excise and other taxes that are collected from
customers and remitted to governmental authorities are not included
in revenue.
Tank Rental Revenue
. We lease petroleum
storage tanks to both related parties and
third-parties. Tank rental fees are invoiced monthly in
accordance with the terms of the related lease
agreement. Tank rental revenue is recognized on a
straight-line basis as earned.
Easement Revenue
. Revenue from land
easement fees was associated with a Master Easement Agreement
between BDPL and FLNG Land II, Inc., a Delaware corporation
(“FLNG”). Easement revenue was recognized
monthly as earned and was included in other income. In
February 2017, BDPL sold approximately 15 acres of property located
in Brazoria County Texas to FLIQ Common Facilities, LLC, an
affiliate of FLNG. In conjunction with the sale of real
estate, the Master Easement Agreement was terminated.
Pipeline Transportation Revenue
.
Revenue from our pipeline operations was derived from fee-based
contracts and was typically based on transportation fees per unit
of volume transported multiplied by the volume delivered. Revenue
was recognized when volumes were physically delivered for the
customer through the pipeline. 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. (See “Note (4) Business Segment
Information” for further discussion related to pipeline
transportation revenue.)
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
Income Taxes
. We account for
income taxes under FASB ASC guidance related to income taxes, which
requires recognition of income taxes based on amounts payable with
respect to the current reporting period and the effects of deferred
taxes for the expected future tax consequences of events that have
been included in our financial statements or tax
returns. Under this method, deferred tax assets and
liabilities are determined based on the differences between the
financial accounting and tax basis of assets and liabilities, as
well as for operating losses and tax credit carryforwards using
enacted tax rates in effect for the year in which the differences
are expected to reverse.
As of each
reporting date, management considers new evidence, both positive
and negative, to determine the realizability of deferred tax
assets. Management considers whether it is more likely
than not that a portion or all the deferred tax assets will be
realized, which is dependent upon the generation of future taxable
income prior to the expiration of any net operating loss
(“NOL”) carryforwards. When management
determines that it is more likely than not that a tax benefit will
not be realized, a valuation allowance is recorded to reduce
deferred tax assets. A significant piece of objective
negative evidence evaluated was the cumulative loss incurred over
the three-year period ended December 31, 2016. Such objective
evidence limits the ability to consider other subjective evidence,
such as our projections for future growth. Based on this
evaluation, we recorded a full valuation allowance against the
deferred tax assets as of December 31, 2016.
FASB ASC guidance
related to income taxes also prescribes a recognition threshold and
measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return, as well as guidance on de-recognition, classification,
interest and penalties, accounting in interim periods, disclosures,
and transition. (See “Note (15) Income
Taxes” for further information related to income
taxes.)
Impairment or Disposal of Long-Lived
Assets
. In accordance with FASB ASC guidance on accounting
for the impairment or disposal of long-lived assets, we
periodically evaluate our long-lived assets for impairment.
Additionally, we evaluate our long-lived assets when events or
circumstances indicate that the carrying value of these assets may
not be recoverable. The carrying value is not recoverable if it
exceeds the sum of the undiscounted cash flows expected to result
from the use and eventual disposition of the asset or group of
assets. If the carrying value exceeds the sum of the undiscounted
cash flows, an impairment loss equal to the amount by which the
carrying value exceeds the fair value of the asset or group of
assets is recognized. Significant management judgment is required
in the forecasting of future operating results that are used in the
preparation of projected cash flows and, should different
conditions prevail or judgments be made, material impairment
charges could be necessary.
Asset Retirement Obligations
.
FASB ASC guidance related to asset retirement obligations
(“AROs”) requires that a liability for the discounted
fair value of an ARO be recorded in the period in which it is
incurred and the corresponding cost capitalized by increasing the
carrying amount of the related long-lived asset. The liability is
accreted towards its future value each period, and the capitalized
cost is depreciated over the useful life of the related asset. If
the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized.
Management has
concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facilities assets arises
and a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
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BLUE DOLPHIN ENERGY
COMPANY
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FORM 10-Q
9/30/17
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Notes to
Consolidated Financial Statements
(Continued)
We recorded an ARO
liability related to future asset retirement costs associated with
dismantling, relocating, or disposing of our offshore platform,
pipeline systems, and related onshore facilities, as well as for
plugging and abandoning wells and restoring land and sea beds. We
developed these cost estimates for each of our assets based upon
regulatory requirements, structural makeup, water depth, reservoir
characteristics, reservoir depth, equipment demand, current
retirement procedures, and construction and engineering
consultations. Because these costs typically extend many
years into the future, estimating future costs are difficult and
require management to make judgments that are subject to future
revisions based upon numerous factors, including changing
technology, political, and regulatory environments. We review our
assumptions and estimates of future abandonment costs on an annual
basis. (See “Note (11) Asset Retirement
Obligations” for additional information related to our
AROs.)
Computation of Earnings Per
Share
. We apply the provisions of FASB ASC guidance for
computing earnings per share (“EPS”). The guidance
requires the presentation of basic EPS, which excludes dilution and
is computed by dividing net income available to common stockholders
by the weighted-average number of shares of common stock
outstanding for the period. The guidance requires dual presentation
of basic EPS and diluted EPS on the face of our consolidated
statements of operations and requires a reconciliation of the
denominator of basic EPS and diluted EPS. Diluted EPS is computed
by dividing net income available to common stockholders by the
diluted weighted average number of common shares outstanding, which
includes the potential dilution that could occur if securities or
other contracts to issue shares of common stock were converted to
common stock that then shared in the earnings of the
entity.
The number of
shares related to options, warrants, restricted stock, and similar
instruments included in diluted EPS is based on the “Treasury
Stock Method” prescribed in FASB ASC guidance for computation
of EPS. This method assumes theoretical repurchase of shares using
proceeds of the respective stock option or warrant exercised, and,
for restricted stock, the amount of compensation cost attributed to
future services that has not yet been recognized and the amount of
any current and deferred tax benefit that would be credited to
additional paid-in-capital upon the vesting of the restricted
stock, at a price equal to the issuer’s average stock price
during the related earnings period. Accordingly, the number of
shares includable in the calculation of EPS in respect of the stock
options, warrants, restricted stock, and similar instruments is
dependent on this average stock price and will increase as the
average stock price increases. (See “Note (16)
Earnings Per Share” for additional information related to
EPS.)
Treasury Stock
. We accounted
for treasury stock under the cost method. In May 2017,
our treasury stock was re-issued. The net change in
share price after acquisition of the treasury stock was recognized
as a component of additional paid-in-capital in our consolidated
balance sheets. (See “Note (12) Treasury
Stock” for additional disclosures related to treasury
stock.)
New Pronouncements
Adopted
. The FASB issues an Accounting Standards
Update (“ASU”) to communicate changes to the FASB ASC,
including changes to non-authoritative SEC
content. Recently adopted ASUs include:
ASU 2016-18, Statement of Cash Flows
(Topic 230: Restricted Cash (A Consensus of the FASB Emerging
Issues Task Force)
. In November 2016, FASB issued ASU
2016-18, which requires that a statement of cash flows explain the
change during the period in the total of cash, cash equivalents,
and amounts generally described as restricted cash or restricted
cash equivalents. We adopted this accounting pronouncement
effective December 31, 2016. Accordingly, our consolidated
statement of cash flows for the nine months ended September 30,
2016 was changed to combine restricted cash with cash and cash
equivalents.
ASU 2015-11,
Inventory (Topic 330):
Simplifying the Measurement of
Inventory
. In July 2015, FASB issued ASU 2015-11, which
requires an entity to measure inventory at the lower of cost or net
realizable value. We adopted this accounting
pronouncement effective January 1, 2017. The adoption of
ASU 2015-11 did not have a significant impact on our consolidated
financial statements.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
New Pronouncements Issued, Not Yet
Effective
. The following are recently issued, but not yet
effective, ASU’s that may influence our consolidated
financial position, results of operations, or cash
flows:
ASU 2017-04, Intangibles – Goodwill and
Other (Topic 350): Simplifying the Test for Goodwill
Impairment.
In January 2017, FASB issued ASU
2017-04. This guidance simplifies the subsequent
measurement of goodwill by eliminating Step 2 from the goodwill
impairment test. For public business entities that are
SEC filers, the amendments in ASU 2017-04 are effective for the
annual or any interim goodwill impairment tests in fiscal years
beginning after December 15, 2019. ASU 2017-04 should be
applied prospectively, and early adoption is permitted for interim
or annual goodwill impairment tests performed on testing dates
after January 1, 2017. We do not expect adoption of this
guidance to have a significant impact on our consolidated balance
sheets.
ASU 2016-02,
Leases (Topic 842)
. In February 2016,
FASB issued ASU 2016-02. This guidance increases transparency
and comparability among organizations by recognizing lease assets
and lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. For a public
business entity, the amendments in ASU 2016-02 are effective for
fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years. Early application is
permitted. We are evaluating the impact that adoption of this
guidance will have on our consolidated balance sheets.
ASU 2014-09, Revenue from Contracts with
Customers
. In May 2014, FASB issued ASU 2014-09
and has since amended the standard with ASU 2015-14
,
R
evenue from Contracts with Customers (Topic
606): Deferral of the Effective Date
;
ASU 2016-08,
Revenue from Contracts with Customers (Topic
606): Principal Versus Agent Considerations (Reporting Revenue
Gross Versus Net)
;
ASU 2016-10,
Revenue from Contracts with Customers (Topic
606): Identifying Performance Obligations and Licensing
; ASU
2016-11,
Revenue Recognition
(Topic 605) and Derivatives and Hedging (Topic 815): Rescission of
SEC Guidance Because of Accounting Standards Updates 2014-09 and
2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF
Meeting (SEC Update)
; ASU 2016-12,
Revenue from Contracts with Customers (Topic
606): Narrow-Scope Improvements and Practical
Expedients
; and ASU 2016-20,
Technical Corrections and Improvements to
Topic 606, Revenue from Contracts with
Customers
. These standards replace existing
revenue recognition rules with a single comprehensive model to use
in accounting for revenue arising from contracts with
customers. We are evaluating the impact that adoption of
these ASU’s will have on our consolidated financial
statements.
Other new
pronouncements issued but not yet effective are not expected to
have a material impact on our financial position, results of
operations, or liquidity.
Reclassification
. Effective
January 1, 2017, we reclassified amounts associated with our
Pipeline Transportation operations to Corporate and
Other. (See “Note (4) Business Segment
Information” for disclosures related to Corporate and
Other.)
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
(4)
Business Segment Information
Effective January
1, 2017, we began reporting as a single business segment –
Refinery Operations. Business activities related to our
Refinery Operations business segment are conducted at the Nixon
Facility. Due to their small size, current and prior
three and nine months’ amounts associated with Pipeline
Transportation operations were reclassified to Corporate and Other.
Pipeline Transportation operations diminished significantly as
services to third-parties ceased and third-party wells along our
pipeline corridor were permanently abandoned. Business
segment information for the periods indicated (and as of the dates
indicated), was as follows:
|
|
Three Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
operations
|
$
66,899,092
|
$
-
|
$
66,899,092
|
$
54,668,780
|
$
19,526
|
$
54,688,306
|
|
Less: cost of
operations
(1)
|
(61,456,546
)
|
(466,912
)
|
(61,923,458
)
|
(55,495,575
)
|
(367,915
)
|
(55,863,490
)
|
|
Other non-interest
income
(2)
|
-
|
-
|
-
|
-
|
156,396
|
156,396
|
|
Less: JMA Profit
Share
(3)
|
-
|
-
|
-
|
(965,627
)
|
-
|
(965,627
)
|
|
EBITDA
(4)
|
$
5,442,546
|
$
(466,912
)
|
|
$
(1,792,422
)
|
$
(191,993
)
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and
|
|
|
|
|
|
|
|
amortization
|
|
|
(455,437
)
|
|
|
(504,719
)
|
|
Interest expense,
net
|
|
|
(574,678
)
|
|
|
(484,215
)
|
|
|
|
|
|
|
|
|
|
Income (loss)
before income taxes
|
|
|
3,945,519
|
|
|
(2,973,349
)
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
-
|
|
|
1,034,798
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
|
$
3,945,519
|
|
|
$
(1,938,551
)
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
$
538,801
|
$
-
|
$
538,801
|
$
4,191,077
|
$
-
|
$
4,191,077
|
|
|
|
|
|
|
|
|
|
Identifiable
assets
|
$
70,791,236
|
$
2,068,269
|
$
72,859,505
|
$
85,585,499
|
$
10,816,664
|
$
96,402,163
|
|
(1)
|
Operation cost
within the Refinery Operations segment includes related general and
administrative expenses. Operation cost within Corporate
and Other includes general and administrative expenses associated
with corporate maintenance costs (such as accounting fees, director
fees, and legal expense), as well as expenses associated with our
pipeline assets and oil and/or gas leasehold interests (such as
accretion and impairment expenses).
|
|
(2)
|
Other non-interest
income reflects FLNG easement revenue.
|
|
(3)
|
The JMA Profit
Share represents the GEL Profit Share plus the Performance Fee for
the period pursuant to the Joint Marketing Agreement, under which
marketing activities have ceased. (See “Note (1)
Organization – Going Concern
– Final
Arbitration Award
” for further discussion related to
the contract-related dispute with GEL.)
|
|
(4)
|
EBITDA is a
non-GAAP financial measure. See “Part I, Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Results of Operations –
Non-GAAP Financial Measures” for additional information
related to EBITDA.
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
|
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
operations
|
$
176,841,172
|
$
-
|
$
176,841,172
|
$
128,171,177
|
$
71,865
|
$
128,243,042
|
|
Less: cost of
operations
(1)
|
(197,706,434
)
|
(1,293,162
)
|
(198,999,596
)
|
(135,452,537
)
|
(1,078,910
)
|
(136,531,447
)
|
|
Other non-interest
income
(2)
|
-
|
-
|
-
|
(392,062
)
|
-
|
(392,062
)
|
|
Less: JMA Profit
Share
(3)
|
-
|
2,216,251
|
2,216,251
|
-
|
412,061
|
412,061
|
|
EBITDA
(4)
|
$
(20,865,262
)
|
$
923,089
|
|
$
(7,673,422
)
|
$
(594,984
)
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and
|
|
|
|
|
|
|
|
amortization
|
|
|
(1,355,780
)
|
|
|
(1,415,519
)
|
|
Interest expense,
net
|
|
|
(1,999,760
)
|
|
|
(1,301,486
)
|
|
|
|
|
|
|
|
|
|
Loss before income
taxes
|
|
|
(23,297,713
)
|
|
|
(10,985,411
)
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
-
|
|
|
3,735,040
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
|
$
(23,297,713
)
|
|
|
$
(7,250,371
)
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
$
3,428,129
|
$
-
|
$
3,428,129
|
$
13,857,434
|
$
-
|
$
13,857,434
|
|
|
|
|
|
|
|
|
|
Identifiable
assets
|
$
70,791,236
|
$
2,068,269
|
$
72,859,505
|
$
85,585,499
|
$
10,816,664
|
$
96,402,163
|
|
(1)
|
Operation cost
within the Refinery Operations segment includes related general and
administrative expenses and the arbitration award and associated
fees. Operation cost within Corporate and Other includes
general and administrative expenses associated with corporate
maintenance costs (such as accounting fees, director fees, and
legal expense), as well as expenses associated with our pipeline
assets and oil and/or gas leasehold interests (such as accretion
and impairment expenses).
|
|
(2)
|
Other non-interest
income reflects FLNG easement revenue.
|
|
(3)
|
The JMA Profit
Share represents the GEL Profit Share plus the Performance Fee for
the period pursuant to the Joint Marketing Agreement, under which
marketing activities have ceased. (See
“Note
(1) Organization
– Going Concern
– Final
Arbitration Award
” for further discussion
related to the contract-related dispute with GEL.)
|
|
(4)
|
EBITDA is a
non-GAAP financial measure. See “Part I, Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Results of Operations –
Non-GAAP Financial Measures” for additional information
related to EBITDA.
|
(5)
Prepaid Expenses and Other Current Assets
Prepaid expenses
and other current assets as of the dates indicated consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid crude oil
and condensate
|
$
1,332,439
|
$
-
|
|
Prepaid
insurance
|
298,913
|
248,853
|
|
Short-term tax
bond
|
-
|
505,000
|
|
Prepaid exise
taxes
|
-
|
292,338
|
|
|
|
|
|
|
$
1,631,352
|
$
1,046,191
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
(6)
Inventory
Inventory as of the
dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and
condensate
|
$
1,207,865
|
$
26,123
|
|
AGO
|
910,189
|
143,362
|
|
HOBM
|
341,660
|
212,987
|
|
Chemicals
|
156,535
|
182,751
|
|
Naphtha
|
135,554
|
533,580
|
|
Propane
|
18,377
|
11,318
|
|
LPG
mix
|
5,260
|
1,293
|
|
Jet
fuel
|
-
|
964,124
|
|
|
|
|
|
|
$
2,775,440
|
$
2,075,538
|
(7)
Property, Pland and Equipment, Net
Property, plant and
equipment, net, as of the dates indicated consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery and
facilities
|
$
51,432,434
|
$
50,814,309
|
|
Land
|
566,159
|
602,938
|
|
Other property and
equipment
|
652,795
|
652,795
|
|
|
52,651,388
|
52,070,042
|
|
|
|
|
|
Less: Accumulated
depletion, depreciation, and amortization
|
(8,041,024
)
|
(6,685,244
)
|
|
|
44,610,364
|
45,384,798
|
|
|
|
|
|
Construction in
progress
|
19,786,447
|
16,939,665
|
|
|
|
|
|
|
$
64,396,811
|
$
62,324,463
|
We capitalize
interest cost incurred on funds used to construct property, plant,
and equipment. The capitalized interest is recorded as
part of the asset to which it relates and is depreciated over the
asset’s useful life. Interest cost capitalized was
$3,413,428 and $2,108,298 at September 30, 2017 and December 31,
2016, respectively.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
(8)
Related Party Transactions
We are party to
several agreements with related parties. We believe
these related party transactions were consummated on terms
equivalent to those that prevail in arm's-length
transactions.
Related Parties
.
LEH
. LEH is our controlling
shareholder. Jonathan Carroll, Chairman of the Board,
Chief Executive Officer, and President of Blue Dolphin, is the
majority owner of LEH. Together LEH and Jonathan Carroll
own approximately 81% of our Common Stock. We are
currently party to an Amended and Restated Operating Agreement, a
Jet Fuel Sales Agreement, a Loan and Security Agreement, an Amended
and Restated Promissory Note, and a Debt Assumption Agreement with
LEH.
Ingleside Crude, LLC
(“Ingleside”)
. Ingleside is a related
party of LEH and Jonathan Carroll. We are currently
party to an Amended and Restated Promissory Note with
Ingleside.
Lazarus Marine Terminal I, LLC
(“LMT”)
. LMT is a related party
of LEH and Jonathan Carroll. We are currently party to a
Tolling Agreement with LMT.
Jonathan Carroll
. Jonathan
Carroll is Chairman of the Board, Chief Executive Officer, and
President of Blue Dolphin. We are currently party to
Amended and Restated Guaranty Fee Agreements and an Amended and
Restated Promissory Note with Jonathan Carroll.
Currently, we
depend on LEH and its affiliates (including Jonathan Carroll and
Ingleside) for financing when revenue from operations and
borrowings under bank facilities are insufficient to meet our
liquidity needs. Such borrowings are reflected in our
consolidated balance sheets in accounts payable, related party,
and/or long-term debt, related party. Each quarter
amounts we owe to related parties are settled with amounts owed to
us by LEH and its affiliates under certain related-party agreements
as discussed within this Note (8), Related Party
Transactions. As a result, these related-party
transactions do not always reflect cash payments between the
parties.
Operations Related
Agreements
.
Amended and Restated Operating
Agreement
. LEH operates and manages all our
properties pursuant to the Amended and Restated Operating
Agreement. The Amended and Restated Operating Agreement,
which was restructured following cessation of crude supply and
marketing activities under the Crude Supply Agreement and Joint
Marketing Agreement with GEL, expires: (i) April 1, 2020, (ii) upon
written notice by either party to the Amended and Restated
Operating Agreement of a material breach by the other party, or
(iii) upon 90 days’ notice by the Board if the Board
determines that the Amended and Restated Operating Agreement is not
in our best interest. We reimburse LEH at cost plus five percent
(5%) for all reasonable Blue Dolphin expenses incurred while LEH
performs the services. These expenses are
reflected within refinery operating expenses in our consolidated
statements of operations.
Jet Fuel Sales Agreement
. We
sell jet fuel and other products to LEH pursuant to a Jet Fuel
Sales Agreement. LEH resells these products to a
government agency. In support of the Jet Fuel
Sales Agreement, we previously leased Nixon Facility petroleum
storage tanks to LEH for the storage of the jet fuel under a
Terminal Services Agreement (as described below). The
Jet Fuel Sales Agreement terminates on the earliest to occur of:
(a) a one-year term expiring March 31, 2018 plus a 30-day carryover
or (b) delivery of a maximum quantity of jet fuel as defined
therein. Sales to LEH under the Jet Fuel Sales Agreement
are reflected within refined petroleum product sales in our
consolidated statements of operations.
Terminal Services
Agreement
. Pursuant to a Terminal Services
Agreement, LEH leased petroleum storage tanks at the Nixon Facility
for the storage of Blue Dolphin purchased jet fuel under the Jet
Fuel Sales Agreement (as described above). The Terminal
Services Agreement was terminated in June 2017. Rental
fees received from LEH under the Terminal Services Agreement are
reflected within tank rental revenue in our consolidated statements
of operations.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Amended and Restated Tank Lease
Agreement
. Pursuant to an Amended and Restated
Tank Lease Agreement with Ingleside, we leased petroleum storage
tanks to meet periodic, additional storage needs. The
Amended and Restated Tank Lease Agreement was terminated in July
2017. Rental fees owed to Ingleside under the tank lease
agreement are reflected within long-term debt, related party, net
of current portion in our consolidated balance sheets. Amounts
expensed as rental fees to Ingleside under the Amended and Restated
Tank Lease Agreement are reflected within refinery operating
expenses in our consolidated statements of operations.
Tolling Agreement
. In May
2016, we entered a Tolling Agreement with LMT to facilitate loading
and unloading of our petroleum products by barge at LMT’s
dock facility in Ingleside, Texas. The Tolling Agreement
has a five-year term and may be terminated at any time by the
agreement of both parties. We pay LMT a flat monthly
reservation fee of $50,400. The monthly reservation fee
includes tolling volumes up to 84,000 gallons per
day. Tolling volumes totaling more than 210,000 gallons
per quarter are billed to us at $0.02 per
gallon. Amounts expensed as tolling fees to LMT under
the Tolling Agreement are reflected in cost of refined products
sold in our consolidated statements of operations.
Financial
Agreements
.
Loan and Security
Agreement
. In August 2016, BDPL entered a loan
and security agreement with LEH as evidenced by a promissory note
in the original principal amount of $4.0 million (the “LEH
Loan Agreement”). The LEH Loan Agreement matures
in August 2018, and accrues interest at rate of
16.00%. Under the LEH Loan Agreement, BDPL makes a
payment to LEH of $500,000 per year. A final balloon
payment is due at maturity.
The proceeds of the
LEH Loan Agreement were used for working capital. There
are no financial maintenance covenants associated with the LEH Loan
Agreement. The LEH Loan Agreement is secured by certain
property owned by BDPL. Outstanding principal owed to LEH under the
LEH Loan Agreement is reflected in long-term debt, related party,
current portion in our consolidated balance
sheets. Accrued interest under the LEH Loan Agreement is
reflected in interest payable, current portion in our consolidated
balance sheets.
Promissory Notes
. We
currently rely on LEH and its affiliates (including Jonathan
Carroll) to fund our working capital requirements. The
below promissory notes represent advances to fund our working
capital requirements. There can be no assurance that LEH and its
affiliates will continue to fund our working capital
requirements.
●
June LEH Note
– In March 2017,
Blue Dolphin entered a promissory note with LEH in the original
principal amount of $440,815 (the “March LEH
Note”). In June 2017, the March LEH Note was
amended and restated to increase the amount by $2,043,482 (the
“June LEH Note”). Interest under the June
LEH Note, which is compounded annually and accrued at a rate of
8.00%, was paid in kind and added to the outstanding
balance. The June LEH Note has a maturity date of
January 2019. Under the June LEH Note, prepayment, in
whole or in part, is permissible at any time and from time to time,
without premium or penalty. Outstanding principal and
accrued interest owed to LEH under the June LEH Note are reflected
in long-term debt, related party, net of current portion in our
consolidated balance sheets. At September 30, 2017 and
December 31, 2016, the outstanding principal and accrued interest
owed to LEH under the June LEH Note and a previous promissory note,
respectively, was $0. The balances under the notes were settled
with amounts owed to us by LEH.
●
March Ingleside Note
– In March
2017, a promissory note between Blue Dolphin and Ingleside was
amended and restated (the “March Ingleside Note”) to
increase the principal amount by $473,445 and extend the maturity
date to January 2019. Interest under the March Ingleside Note,
which is compounded annually and accrued at a rate of 8.00%, was
paid in kind and added to the outstanding balance. Under
the March Ingleside Note, prepayment, in whole or in part, is
permissible at any time and from time to time, without premium or
penalty. Outstanding principal and accrued interest owed
to Ingleside under the March Ingleside Note are reflected in
long-term debt, related party, net of current portion in our
consolidated balance sheets. At September 30, 2017 and December 31,
2016, the outstanding principal and accrued interest owed to
Ingleside under the March Ingleside Note was $1,168,748 and
$722,278, respectively.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
●
March Carroll Note
– In March
2017, a promissory note between Blue Dolphin and Jonathan Carroll
was amended and restated (the “March Carroll Note”) to
increase the principal amount by $183,030, revise the payment terms
to reflect payment in cash and shares of Blue Dolphin Common Stock,
and extend the maturity date to January 2019. Interest
under the March Carroll Note, which is compounded annually and
accrued at a rate of 8.00%, was paid in kind and added to the
outstanding balance. Under the March Carroll Note,
prepayment, in whole or in part, is permissible at any time and
from time to time, without premium or
penalty. Outstanding principal and accrued interest owed
to Jonathan Carroll under the March Carroll Note are reflected in
long-term debt, related party, net of current portion in our
consolidated balance sheets. At September 30, 2017 and December 31,
2016, the outstanding principal and accrued interest owed to
Jonathan Carroll under the March Carroll Note was $282,907 and
$592,412, respectively.
Debt Assumption Agreement
. On September 18, 2017, LEH paid, on
LE’s behalf, certain obligations totaling $3,648,742 to GEL
in connection with the GEL Arbitration and the GEL Letter
Agreement. In exchange for such payments, LE agreed to assume
$3,677,953 of LEH’s existing indebtedness pursuant to the
Debt Assumption Agreement, entered into on November 14, 2017 and
made effective September 18, 2017, by and among LE, LEH and John H.
Kissick.
Amended and
Restated Guaranty Fee Agreements
. Pursuant to
Amended and Restated Guaranty Fee Agreements, Jonathan Carroll
receives fees for providing his personal guarantee on certain of
our long-term debt. Jonathan Carroll was required to
guarantee repayment of funds borrowed and interest accrued under
certain loan agreements. Amounts owed to Jonathan
Carroll under Amended and Restated Guaranty Fee Agreements are
reflected within long-term debt, related party, net of current
portion in our consolidated balance sheets. Amounts
expensed related to Amended and Restated Guarantee Fee Agreements
are reflected within interest and other expense in our consolidated
statements of operations. (See “Note (10)
Long-Term Debt, Net” for further discussion related to these
guaranty fee agreements.)
Financial Statements
Impact
.
Consolidated Balance
Sheets
. Accounts payable, related party to LMT
associated with the Tolling Agreement was $823,200 and $369,600 at
September 30, 2017 and December 31, 2016,
respectively. Long-term debt, related party associated
with the LEH Loan Agreement, June LEH Note, March Ingleside Note,
and March Carroll Note as of the dates indicated was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
4,000,000
|
$
4,000,000
|
|
Ingleside
|
1,168,748
|
722,278
|
|
Jonathan
Carroll
|
282,907
|
592,412
|
|
|
|
|
|
|
5,451,655
|
5,314,690
|
|
|
|
|
|
Less: Long-term
debt, related party,
|
|
|
|
current
portion
|
(4,000,000
)
|
(500,000
)
|
|
|
|
|
|
|
$
1,451,655
|
$
4,814,690
|
Accrued interest
associated with the LEH Loan Agreement was $728,889 and $243,556 at
September 30, 2017 and December 31, 2016,
respectively.
Consolidated Statements of
Operations
. Related party revenue from LEH
associated with:
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet fuel
sales
|
$
20,802,789
|
$
14,536,997
|
$
56,360,756
|
$
23,449,071
|
|
Jet fuel storage
fees
|
56,386
|
426,000
|
675,000
|
750,000
|
|
HOBM
sales
|
-
|
-
|
3,425,455
|
-
|
|
|
|
|
|
|
|
|
$
20,859,175
|
$
14,962,997
|
$
60,461,211
|
$
24,199,071
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Related party cost
of goods sold associated with the Tolling Agreement with LMT
totaled $151,200 and $0 for the three months ended September 30,
2017 and 2016; related party cost of goods sold for the nine months
ended September 30, 2017 and 2016 totaled $453,600 and
$0.
Related party
refinery operating expenses associated with the Amended and
Restated Operating Agreement with LEH and the Amended and Restated
Tank Lease Agreement with Ingleside for the periods indicated were
as follows:
|
|
Three Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
1,758,005
|
$
1.53
|
$
3,028,646
|
$
2.66
|
|
Ingleside
|
-
|
-
|
125,000
|
0.11
|
|
|
|
|
|
|
|
|
$
1,758,005
|
$
1.53
|
$
3,153,646
|
$
2.77
|
|
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
6,222,771
|
$
1.93
|
$
8,618,409
|
$
2.84
|
|
Ingleside
|
-
|
-
|
850,000
|
0.28
|
|
|
|
|
|
|
|
|
$
6,222,771
|
$
1.93
|
$
9,468,409
|
$
3.12
|
For the three
months ended September 30, 2017, refinery operating expenses per
bbl decreased compared to the three months ended September 30, 2016
due to the revised cost-plus expense reimbursement structure under
the Amended and Restated Operating Agreement. The Amended and
Restated Operating Agreement was effective in April
2017.
For the nine months
ended September 2017, refinery operating expenses per bbl decreased
compared to the nine months ended September 30, 2017 due to the
revised cost-plus expense reimbursement structure as noted
above. In addition, refinery operating expenses per bbl
were higher during the nine months ended September 30, 2016 due to
significant refinery downtime.
Interest expense
associated with the LEH Loan Agreement and Amended and Restated
Guaranty Fee Agreements for the periods indicated was as
follows:
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
201,361
|
$
80,000
|
$
643,046
|
$
80,000
|
|
Jonathan
Carroll
|
165,089
|
172,300
|
499,184
|
522,931
|
|
|
|
|
|
|
|
|
$
366,450
|
$
252,300
|
$
1,142,230
|
$
602,931
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
(9)
Accrued Expenses and Other Current Liabilities
Accrued expenses
and other current liabilities as of the dates indicated consisted
of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unearned
revenue
|
$
708,567
|
$
408,770
|
|
Board of director
fees payable
|
203,929
|
136,429
|
|
Customer
deposits
|
109,029
|
450,000
|
|
Property
taxes
|
99,236
|
4,694
|
|
Excise and income
taxes payable
|
60,692
|
24,187
|
|
Other
payable
|
38,621
|
189,719
|
|
Insurance
|
-
|
67,783
|
|
|
|
|
|
|
$
1,220,074
|
$
1,281,582
|
(10)
Long-Term Debt, Net
Long-term debt, net
represents the outstanding principal of long-term debt less
associated debt issue costs. Long-term debt, net as of
the dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Term Loan Due
2034 (in default)
|
$
23,382,570
|
$
23,924,607
|
|
Second Term Loan
Due 2034 (in default)
|
9,553,728
|
9,729,853
|
|
Notre Dame
Debt
|
4,977,953
|
1,300,000
|
|
Term Loan Due
2017
|
-
|
184,994
|
|
Capital
Leases
|
8,427
|
135,879
|
|
|
$
37,922,678
|
$
35,275,333
|
|
|
|
|
|
Less: Current
portion of long-term debt, net
|
(35,756,045
)
|
(31,712,336
)
|
|
|
|
|
|
Less: Unamortized
debt issue costs
|
(2,166,633
)
|
(2,262,997
)
|
|
|
|
|
|
|
$
-
|
$
1,300,000
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Unamortized debt
issue costs, which relate to secured loan agreements with Veritex,
as of the dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Term Loan Due
2034 (in default)
|
$
1,673,545
|
$
1,673,545
|
|
Second Term Loan
Due 2034 (in default)
|
767,673
|
767,673
|
|
|
|
|
|
Less: Accumulated
amortization
|
(274,585
)
|
(178,221
)
|
|
|
|
|
|
|
$
2,166,633
|
$
2,262,997
|
Amortization
expense associated with long-term debt, net, which is included in
interest expense, was $32,121 and $32,121 for the three months
ended September 30, 2017 and 2016,
respectively. Amortization expense was $96,363 and
$96,364 for the nine months ended September 30, 2017 and 2016,
respectively.
Accrued interest
associated with long-term debt, net is reflected as interest
payable, current portion and long-term interest payable, net of
current portion in our consolidated balance sheets and includes
related party interest. Accrued interest as of the dates
indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Notre Dame
Debt
|
$
1,846,964
|
$
1,691,383
|
|
LEH Loan Agreement
(related party)
|
728,889
|
243,556
|
|
Second Term Loan
Due 2034 (in default)
|
47,635
|
44,984
|
|
First Term Loan Due
2034 (in default)
|
35,875
|
33,866
|
|
Capital
Leases
|
423
|
1,165
|
|
Term Loan Due
2017
|
-
|
185
|
|
|
|
|
|
|
2,659,786
|
2,015,139
|
|
|
|
|
|
Less: Interest
payable, current portion
|
(2,659,786
)
|
(323,756
)
|
|
|
|
|
|
Long-term interest
payable, net of current portion
|
$
-
|
$
1,691,383
|
Related Party
. See
“Note (8) Related Party Transactions” for additional
disclosures with respect to related party long-term
debt.
First Term Loan Due 2034 (In
Default)
. LE has a 2015 loan agreement and related security
agreement
with Veritex
as administrative agent and lender. The loan agreement
is for
a term loan in the
principal amount of $25.0 million
(the “First Term
Loan Due 2034”). The First Term Loan Due 2034
matures in June 2034, has a current monthly payment of principal
and interest of $198,786, and accrues interest at a rate based on
the Wall Street Journal Prime Rate plus 2.75%. Pursuant
to a construction rider in the First Term Loan Due 2034, proceeds
available for use were placed in a disbursement account whereby
Veritex makes payments for construction related expenses. Amounts
held in the disbursement account are reflected as restricted cash
(current portion) and restricted cash, noncurrent in our
consolidated balance sheets.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
As described
elsewhere in this Quarterly Report, Veritex notified LE that the
Final Arbitration Award constitutes an event of default under the
First Term Loan Due 2034. In addition to existing or
potential events of default related to the Final Arbitration Award,
at September 30, 2017, LE was in violation of the debt service
coverage ratio, the current ratio, and debt to net worth ratio
financial covenants related to the first Term Loan Due
2034. LE also failed to replenish a payment reserve
account as required. The occurrence of events of default
under the First Term Loan Due 2034 permits Veritex to declare the
amounts owed under the First Term Loan Due 2034 immediately due and
payable, exercise its rights with respect to collateral securing
LE’s obligations under the loan agreement, and/or exercise
any other rights and remedies available. Veritex
informed obligors that it is not currently exercising its rights,
privileges and remedies under the First Term Loan Due 2034 in light
of 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 First Term Loan Due 2034 and informed LE that
it would consider a final confirmation of the Final Arbitration
Award to be a material event of default under the loan
agreement. Any exercise by Veritex of its rights and
remedies under the First Term Loan Due 2034 would have a material
adverse effect on our business, financial condition and results of
operations and likely would require us to seek protection under
bankruptcy laws. (See “Note (1) Organization
– Going Concern and Operating Risks” for additional
disclosures related to the First Term Loan Due 2034, the Final
Arbitration Award and financial covenant violations.)
As a condition of
the First Term Loan Due 2034, Jonathan Carroll was required to
guarantee r
epayment
of funds borrowed and interest accrued under the
loan. For his personal guarantee, LE entered a Guaranty
Fee Agreement with Jonathan Carroll whereby he receives a fee equal
to 2.00% per annum, paid monthly, of the outstanding principal
balance owed under the First Term Loan Due
2034. Effective in April 2017, the Guaranty Fee
Agreement associated with the First Term Loan Due 2034 was amended
and restated to reflect payment in cash and shares of Blue Dolphin
Common Stock. For the three months ended September 30,
2017 and 2016, guaranty fees related to the First Term Loan Due
2034 totaled $117,214 and $121,048, respectively. For the nine
months ended September 30, 2017 and 2016, guaranty fees related to
the First Term Loan Due 2034 totaled $354,286 and $365,420,
respectively. Guaranty fees are recognized monthly as incurred and
are included in interest and other expense in our consolidated
statements of operations. LEH, LRM and Blue Dolphin also
guaranteed the First Term Loan Due 2034. (See
“Note (8) Related Party Transactions” for additional
disclosures related to LEH and Jonathan Carroll)
A portion of the
proceeds of the First Term Loan Due 2034 were used to refinance
approximately $8.5 million of debt owed under a previous debt
facility with American First National Bank. Remaining
proceeds are being used primarily to construct new petroleum
storage tanks at the Nixon Facility. The First Term Loan Due 2034
is secured by: (i) a first lien on all Nixon Facility business
assets (excluding accounts receivable and inventory), (ii)
assignment of all Nixon Facility contracts, permits, and licenses,
(iii) absolute assignment of Nixon Facility rents and leases,
including tank rental income, (iv) a payment reserve account held
by Veritex, and (v) a pledge of $5.0 million of a life insurance
policy on Jonathan Carroll. The First Term Loan Due 2034
contains representations and warranties, affirmative, restrictive,
and financial covenants, as well as events of default which are
customary for bank facilities of this type.
Second Term Loan Due 2034 (In
Default)
. LRM has a 2015 loan agreement and related security
agreement with Veritex as administrative agent and
lender. The loan agreement is for a term loan in the
principal amount of $10.0 million (the “Second Term Loan Due
2034”). The Second Term Loan Due 2034 matures in
December 2034, has a current monthly payment of principal and
interest of $74,111, and accrues interest at a rate based on the
Wall Street Journal Prime Rate plus 2.75%. Pursuant to a
construction rider in the Second Term Loan Due 2034, proceeds
available for use were placed in a disbursement account whereby
Veritex makes payments for construction related expenses. Amounts
held in the disbursement account are reflected as restricted cash
(current portion) and restricted cash, noncurrent in our
consolidated balance sheets.
As described
elsewhere in this Quarterly Report, Veritex notified LRM that the
Final Arbitration Award constitutes an event of default under the
Second Term Loan Due 2034. In addition to existing or
potential events of default related to the Final Arbitration Award,
at September 30, 2017, LRM was in violation of the debt service
coverage ratio, the current ratio, and debt to net worth ratio
financial covenants related to the Second Term Loan Due
2034. The occurrence of events of default under the
Second Term Loan Due 2034 permits Veritex to declare the amounts
owed under the Second Term Loan Due 2034 immediately due and
payable, exercise its rights with respect to collateral securing
LRM’s obligations under the loan agreement, and/or exercise
any other rights and remedies available. Veritex
informed obligors that it is not currently exercising its rights,
privileges and remedies under the Second Term Loan Due 2034
considering the 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 Second Term Loan Due 2034 and
informed LRM that it would consider a final confirmation of the
Final Arbitration Award to be a material event of default under the
loan agreement. Any exercise by Veritex of its rights
and remedies under the Second Term Loan Due 2034 would have a
material adverse effect on our business, financial condition and
results of operations and likely would require us to seek
protection under bankruptcy laws. (See “Note (1) Organization
– Going Concern and Operating Risks” for additional
disclosures related to the First Term Loan Due 2034, the Final
Arbitration Award and financial covenant violations.)
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
As a condition of
the Second Term Loan Due 2034, Jonathan Carroll was required to
guarantee repayment of funds borrowed and interest accrued under
the loan. For his personal guarantee, LRM entered a
Guaranty Fee Agreement with Jonathan Carroll whereby he receives a
fee equal to 2.00% per annum, paid monthly, of the outstanding
principal balance owed under the Second Term Loan Due
2034. Effective in April 2017, the Guaranty Fee
Agreement associated with the Second Term Loan Due 2034 was amended
and restated to reflect payment in cash and shares of Blue Dolphin
Common Stock. For the three months ended September 30,
2017 and 2016, guaranty fees related to the Second Term Loan Due
2034 totaled $47,874 and $49,094, respectively. For the
nine months ended September 30, 2017 and 2016, guaranty fees
related to the Second Term Loan Due 2034 totaled $144,487 and
$148,261, respectively. Guaranty fees are recognized
monthly as incurred and are included in interest and other expense
in our consolidated statements of operations. LEH,
LE and Blue Dolphin also guaranteed the Second Term Loan Due
2034. (See “Note (8) Related Party
Transactions” for additional disclosures related to LEH and
Jonathan Carroll.)
A portion of the
proceeds of the Second Term Loan Due 2034 were used to refinance a
previous bridge loan from Veritex in the amount of $3.0
million. Remaining proceeds are being used primarily to
construct additional new petroleum storage tanks at the Nixon
Facility. The Second Term Loan Due 2034 is secured by: (i) a second
priority lien on the rights of LE in the Nixon Facility and the
other collateral of LE pursuant to a security agreement; (ii) a
first priority lien on the real property interests of LRM; (iii) a
first priority lien on all of LRM’s fixtures, furniture,
machinery and equipment; (iv) a first priority lien on all of
LRM’s contractual rights, general intangibles and
instruments, except with respect to LRM’s rights in its
leases of certain specified tanks, with respect to which Veritex
has a second priority lien in such leases subordinate to a prior
lien granted by LRM to Veritex to secure obligations of LRM under
the Term Loan Due 2017; and (v) all other collateral as described
in the security documents. The Second Term Loan Due 2034
contains representations and warranties, affirmative, restrictive,
and financial covenants, as well as events of default which are
customary for bank facilities of this type.
Notre Dame Debt
. LE entered a
loan with Notre Dame Investors, Inc. as evidenced by a promissory
note in the original principal amount of $8.0 million, which is
currently held by John Kissick (the “Notre Dame Debt”).
The Notre Dame Debt matures in January 2018, and accrues interest
at a rate of 16.00%.
Pursuant to a Sixth
Amendment to the Notre Dame Debt, entered into on November 14, 2017
and made effective September 18, 2017, the Notre Dame Debt was
amended to increase the principal amount by $3,677,953 (the
“Additional Principal”). The Additional Principal was
used to make payments to GEL to reduce the balance of the Final
Arbitration Award in the amount of $3,648,742 in accordance with
the GEL Letter Agreement.
The Notre Dame Debt
is secured by a Deed of Trust, Security Agreement and Financing
Statements (the “Subordinated Deed of Trust”), which
encumbers the Nixon Facility and general assets of
LE. There are no financial maintenance covenants
associated with the Notre Dame Debt. Pursuant to a
Subordination Agreement dated June 2015, the holder of the Notre
Dame Debt agreed to subordinate any security interest and liens on
the Nixon Facility, as well as its right to payments, in favor of
Veritex as holder of the First Term Loan Due 2034.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Term Loan Due 2017
. LRM had a
2014 loan and security agreement with Veritex for a term loan
facility in the principal amount of $2.0 million (the “Term
Loan Due 2017”). The Term Loan Due 2017 was
amended in March 2015, pursuant to a Loan Modification Agreement
(the “March Loan Modification
Agreement”). Under the March Loan Modification
Agreement, the interest rate was modified to be the greater of the
Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due
date was extended to March 2017. Pursuant to the March
Loan Modification Agreement, the Term Loan Due 2017 had a monthly
principal payment of $61,665 plus interest. The Term Loan Due 2017
was paid off in March 2017.
As a condition of
the Term Loan Due 2017, Jonathan Carroll was required to guarantee
r
epayment
of funds
borrowed and interest accrued under the loan. For his
personal guarantee, LRM entered a Guaranty Fee Agreement with
Jonathan Carroll whereby he received a fee equal to 2.00% per
annum, paid monthly, of the outstanding principal balance owed
under the Term Loan Due 2017. Effective in April 2017,
the Guaranty Fee Agreement associated with the Term Loan Due 2017
was amended and restated to reflect payment in cash and shares of
Blue Dolphin Common Stock. (Guaranty Fee Agreements
associated with the First Term Loan Due 2034, Second Term Loan Due
2034, and Term Loan Due 2017 are collectively referred to in this
Quarterly Report as the “Amended and Restated Guaranty Fee
Agreements”). For the three months ended September
30, 2017 and 2016, guaranty fees related to the Term Loan Due 2017
totaled $0 and $2,158, respectively. For the nine months ended
September 30, 2017 and 2016, guaranty fees related to the Term Loan
Due 2017 totaled $411 and $9,250, respectively. Guaranty fees are
recognized monthly as incurred and are included in interest and
other expense in our consolidated statements of
operations.
Capital Leases
. LRM entered a
36-month build-to-suit capital lease in August 2014 for the
purchase of new boiler equipment for the Nixon
Facility. The equipment, which was delivered in December
2014, was added to construction in progress. Once placed
in service, the equipment will be reclassified to refinery and
facilities and depreciation will begin. The capital lease, which
requires a quarterly payment in the amount of $44,258, is
guaranteed by Blue Dolphin.
A summary of
equipment held under long-term capital leases as of the dates
indicated follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Boiler
equipment
|
$
538,598
|
$
538,598
|
|
Less: accumulated
depreciation
|
-
|
-
|
|
|
|
|
|
|
$
538,598
|
$
538,598
|
(11)
Asset Retirement Obligations
Refinery and Facilities
.
Management has concluded that there is no legal or contractual
obligation to dismantle or remove the refinery and facilities
assets. Management believes that the refinery and facilities assets
have indeterminate lives under FASB ASC guidance for estimating
AROs because dates or ranges of dates upon which we would retire
these assets cannot reasonably be estimated at this time. When a
legal or contractual obligation to dismantle or remove the refinery
and facilities assets arises and a date or range of dates can
reasonably be estimated for the retirement of these assets, we will
estimate the cost of performing the retirement activities and
record a liability for the fair value of that cost using present
value techniques.
Pipelines and Facilities and Oil and
Gas Properties
. We have AROs associated with the
dismantlement and abandonment in place of our pipelines and
facilities assets, as well as the plugging and abandonment of our
oil and gas properties. We recorded a discounted
liability for the fair value of an ARO with a corresponding
increase to the carrying value of the related long-lived asset at
the time the asset was installed or placed in service. We
depreciate the amount added to property and equipment and recognize
accretion expense relating to the discounted liability over the
remaining life of the asset. Plugging and abandonment costs are
recorded during the period incurred or as information becomes
available to substantiate actual and/or probable
costs.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Changes to our ARO
liability for the periods indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement
obligations, at the beginning of the period
|
$
2,027,639
|
$
1,985,864
|
|
Liabilities
settled
|
(445
)
|
(70,969
)
|
|
Accretion
expense
|
215,532
|
112,744
|
|
|
2,242,726
|
2,027,639
|
|
Less: asset
retirement obligations, current portion
|
(17,065
)
|
(17,510
)
|
|
|
|
|
|
Long-term asset
retirement obligations, at the end of the period
|
$
2,225,661
|
$
2,010,129
|
Liabilities settled
represents amounts paid for plugging and abandonment costs against
the asset’s ARO liability. At September 30, 2017
and December 31, 2016, we recognized $445 and $70,969,
respectively, in liabilities settled. Abandonment expense
represents amounts paid for plugging and abandonment costs that
exceed the asset’s ARO liability. For the three
and nine months ended September 30, 2017 and 2016, we recognized $0
in abandonment expense.
(12)
Treasury Stock
At September 30,
2017 and December 31, 2016, we had 0 and 150,000 shares of treasury
stock, respectively. In May 2017, we issued 150,000
shares of treasury stock to Jonathan Carroll as payment for amounts
due under the March Carroll Note. The issuance price of the
treasury stock issued to Mr. Carroll was $2.48 per share, which
reperesents the preceding 30-day average closing price of the
Common Stock, in accordance with the Amended and Restated Guaranty
Fee Agreements. The shares of treasury stock issued to
Mr. Carroll are restricted per applicable securities holding
periods for affiliates.
(13)
Concentration of Risk
Bank Accounts
. Financial
instruments that potentially subject us to concentrations of risk
consist primarily of cash, trade receivables and payables. We
maintain our cash balances at financial institutions located in
Houston, Texas. In the U.S., the Federal Deposit Insurance
Corporation (the “FDIC”) insures certain financial
products up to a maximum of $250,000 per depositor. At
September 30, 2017 and December 31, 2016, we had cash balances
(including restricted cash) of more than the FDIC insurance limit
per depositor in the amount of $1,183,652 and $5,372,689,
respectively.
Key Supplier
.
We purchased light
crude oil and condensate for the Nixon Facility from GEL pursuant
to the Crude Supply Agreement. As discussed elsewhere in
this Quarterly Report, we ceased purchases of crude oil and
condensate from GEL under the Crude Supply Agreement in November
2016. (See “Part I, Item 1 Financial Statements
– Note (18) Commitments and Contingencies – Legal
Matters” in this Quarterly Report for disclosures related to
the Crude Supply Agreement, the contract-related dispute with GEL,
and the Final Arbitration Award.)
We currently have
in place a month-to-month evergreen crude supply contract with a
major integrated oil and gas company. This new 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. The Final Arbitration Award could have a
material adverse effect on our ability to procure adequate amounts
and crude oil and condensate from our current supplier or
otherwise.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Significant Customers
. We
routinely assess the financial strength of our customers and have
not experienced significant write-downs in our accounts receivable
balances. Therefore, we believe that our accounts
receivable credit risk exposure is limited.
For the three
months ended September 30, 2017, we had 4 customers that accounted
for approximately 84% of our refined petroleum product sales. LEH,
a related party, was 1 of these 4 significant customers and
accounted for approximately 32% of our refined petroleum product
sales. At September 30, 2017, these 4 customers
represented approximately $1.5 million in accounts
receivable. LEH represented approximately $1.1 million
in accounts receivable.
For the three
months ended September 30, 2016, we had 4 customers that accounted
for approximately 70% 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 September 30, 2016, these 4 customers
represented approximately $6.7 million in accounts
receivable. LEH represented approximately $2.9 million
in accounts receivable.
For the nine months
ended September 30, 2017, we had 3 customers that accounted for
approximately 67% of our refined petroleum product
sales. LEH was 1 of these 3 significant customers and
accounted for approximately 34% of our refined petroleum product
sales. At September 30, 2017, these 3 customers
represented approximately $1.2 million in accounts
receivable. LEH represented approximately $1.1 million
in accounts receivable.
For the nine months
ended September 30, 2016, we had 4 customers that accounted for
approximately 64% of our refined petroleum product
sales. LEH was one of these 4 significant customers and
accounted for approximately 19% of our refined petroleum product
sales. At September 30, 2016, these 4 customers represented
approximately $5.5 in accounts receivable. LEH
represented approximately $2.9 million in accounts
receivable.
LEH purchases our
jet fuel and resells the jet fuel to a government
agency. (See “Note (8) Related Party
Transactions” for additional disclosures related to our sale
of jet fuel to LEH under the Jet Fuel Sales Agreement and the
associated storage of LEH’s purchased jet fuel under the
Terminal Services Agreement.)
Refined Petroleum Product
Sales
. Our refined petroleum products are primarily sold in
the U.S. However, with the opening of the Mexican diesel market to
private companies, we began exporting some of our low-sulfur diesel
to Mexico during the second quarter of 2016. Total
refined petroleum product sales by distillation (from light to
heavy) for the periods indicated consisted of the
following:
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LPG mix
|
$
-
|
0.0
%
|
$
237,009
|
0.4
%
|
$
120,542
|
0.1
%
|
$
621,313
|
0.5
%
|
|
Naphtha
|
14,266,056
|
21.6
%
|
11,870,484
|
22.0
%
|
41,282,969
|
24.9
%
|
28,183,809
|
22.3
%
|
|
Jet fuel
|
20,802,789
|
31.5
%
|
15,104,900
|
28.0
%
|
56,360,757
|
32.8
%
|
41,150,686
|
32.5
%
|
|
HOBM
|
17,011,443
|
25.7
%
|
14,206,759
|
26.4
%
|
38,580,236
|
19.9
%
|
25,259,753
|
20.0
%
|
|
Reduced Crude
|
-
|
0.0
%
|
-
|
0.0
%
|
-
|
0.0
%
|
3,791,919
|
3.0
%
|
|
AGO
|
14,052,671
|
21.2
%
|
12,532,141
|
23.2
%
|
38,323,113
|
22.3
%
|
27,539,236
|
21.7
%
|
|
|
|
|
|
|
|
|
|
|
|
|
$
66,132,959
|
100.0
%
|
$
53,951,293
|
100.0
%
|
$
174,667,617
|
100.0
%
|
$
126,546,716
|
100.0
%
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
(14)
Leases
Our company
headquarters are in downtown Houston, Texas. We lease
13,878 square feet of office space, 7,389 square feet of which is
used and paid for by LEH. The office lease had a 10-year term
expiring in September 2017, but we extended the lease through
December 2017. We are currently exploring our leasing
options. Rent expense is recognized on a straight-line
basis. For the three months ended September 30, 2017 and
2016, rent expense totaled $31,681 and $33,251,
respectively. For the nine months ended September 30,
2017 and 2016, rent expense totaled $107,853 and $92,966,
respectively.
(15)
Income Taxes
Income Tax
Benefit
. For the three months ended September 30,
2017 and 2016, we recognized an income tax benefit of $0 and
$1,034,798 respectively. For the nine months ended September 30,
2017 and 2016, we recognized an income tax benefit of $0 and
$3,735,040, respectively.
Deferred Income
Taxes
. Deferred income tax balances reflect the
effects of temporary differences between the carrying amounts of
assets and liabilities and their tax basis, as well as from NOL
carryforwards. We state those balances at the enacted
tax rates we expect will be in effect when taxes are
paid. NOL carryforwards and deferred tax assets
represent amounts available to reduce future taxable
income.
NOL Carryforwards
. Under
Section 382 of the Internal Revenue Code of 1986, as amended
(“IRC Section 382”), a corporation that undergoes an
“ownership change” is subject to limitations on its use
of pre-change NOL carryforwards to offset future taxable income.
Within the meaning of IRC Section 382, an “ownership
change” occurs when the aggregate stock ownership of certain
stockholders (generally 5% shareholders, applying certain
look-through rules) increases by more than 50 percentage points
over such stockholders' lowest percentage ownership during the
testing period (generally three years). For income tax purposes, we
experienced ownership changes in 2005, relating to a series of
private placements, and in 2012, because of a reverse acquisition,
that limit the use of pre-change NOL carryforwards to offset future
taxable income. In general, the annual use limitation
equals the aggregate value of common stock at the time of the
ownership change multiplied by a specified tax-exempt interest
rate. The 2012 ownership change will subject approximately $16.3
million in NOL carryforwards that were generated prior to the
ownership change to an annual use limitation of $638,196 per
year. Unused portions of the annual use limitation
amount may be used in subsequent years. As a result of
the annual use limitation, approximately $6.7 million in NOL
carryforwards that were generated prior to the 2012 ownership
change will expire unused. NOL carryforwards that were
generated after the 2012 ownership change are not subject to an
annual use limitation under IRC Section 382 and may be used for a
period of 20 years in addition to available amounts of NOL
carryforwards generated prior to the ownership change.
Remainder of Page
Intentionally Left Blank
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
NOL carryforwards
that remained available for future use for the periods indicated
were as follow (amounts shown are net of NOLs that will expire
unused because of the IRC Section 382 limitation):
|
|
Net Operating
Loss Carryforward
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December
31, 2015
|
$
9,614,449
|
$
9,616,941
|
$
19,231,390
|
|
|
|
|
|
|
Net operating
losses
|
-
|
13,945,128
|
13,945,128
|
|
|
|
|
|
|
Balance at December
31, 2016
|
$
9,614,449
|
$
23,562,069
|
$
33,176,518
|
|
|
|
|
|
|
Net operating
losses
|
-
|
6,469,611
|
6,469,611
|
|
|
|
|
|
|
Balance at
September 30, 2017
|
$
9,614,449
|
$
30,031,680
|
$
39,646,129
|
Deferred Tax Assets and
Liabilities
. At September 30, 2017 and December
31, 2016, we had $0 of net deferred tax assets available for future
use. Significant components of deferred tax assets and
liabilities as of the dates indicated were as follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax
assets:
|
|
|
|
Net operating loss
and capital loss carryforwards
|
$
15,750,006
|
$
13,550,338
|
|
Accrued arbitration
award payable
|
6,674,017
|
-
|
|
Start-up costs
(Nixon Facility)
|
1,270,361
|
1,373,363
|
|
Asset retirement
obligations liability/deferred revenue
|
780,249
|
717,751
|
|
AMT credit and
other
|
224,647
|
266,522
|
|
Total deferred tax
assets
|
24,699,280
|
15,907,974
|
|
|
|
|
|
Deferred tax
liabilities:
|
|
|
|
Basis differences
in property and equipment
|
(6,762,850
)
|
(5,895,943
)
|
|
Total deferred tax
liabilities
|
(6,762,850
)
|
(5,895,943
)
|
|
|
|
|
|
|
17,936,430
|
10,012,031
|
|
|
|
|
|
Valuation
allowance
|
(17,936,430
)
|
(10,012,031
)
|
|
|
|
|
|
Deferred tax
assets, net
|
$
-
|
$
-
|
Valuation Allowance
. As of each
reporting date, management considers new evidence, both positive
and negative, to determine the realizability of deferred tax
assets. Management considers whether it is more likely
than not that some portion or all the deferred tax assets will be
realized, which is dependent upon the generation of future taxable
income prior to the expiration of any NOL carryforwards. At
September 30, 2017 and December 31, 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 September 30, 2017
and December 31, 2016.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
Uncertain Tax Positions
. We
adopted the provisions of the FASB ASC guidance on accounting for
uncertainty in income taxes. The guidance clarifies the accounting
for uncertainty in income taxes recognized in an enterprise’s
financial statements. The guidance also prescribes a recognition
threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to
be taken in a tax return. The standard also provides guidance on
de-recognition, classification, interest and penalties, accounting
in interim periods, disclosure and transition.
As part of this
guidance, we record income tax related interest and penalties, if
applicable, as a component of the provision for income tax benefit
(expense). However, there were no amounts recognized relating to
interest and penalties in the consolidated statements of operations
for the three and nine months ended September 30, 2017 and 2016.
Our federal income tax returns are subject to examination by the
Internal Revenue Service for tax years ending December 31, 2013, or
after and by the state of Texas for tax years ending December 31,
2012, or after. We believe there are no uncertain tax
positions for both federal and state income taxes.
(16)
Earnings Per Share
A reconciliation
between basic and diluted income per share for the periods
indicated was as follows:
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
3,945,519
|
$
(1,938,551
)
|
$
(23,297,713
)
|
$
(7,250,371
)
|
|
|
|
|
|
|
|
Basic and diluted
income per share
|
$
0.36
|
$
(0.19
)
|
$
(2.19
)
|
$
(0.69
)
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
|
|
|
|
Weighted average
number of shares of
|
|
|
|
|
|
common stock
outstanding and potential
|
|
|
|
|
|
dilutive shares of
common stock
|
10,818,371
|
10,464,715
|
10,644,654
|
10,460,849
|
Diluted EPS is
computed by dividing net income available to common stockholders by
the weighted average number of shares of common stock
outstanding. Diluted EPS for the three and nine months
ended September 30, 2017 and 2016 was the same as basic EPS as
there were no stock options or other dilutive instruments
outstanding.
(17)
Inventory Risk Management
During 2017, we
began selling all our jet fuel immediately following production,
which minimizes inventory, improves cash flow, and reduces
commodity risk/exposure. Previously, Genesis/GEL used
commodity futures contracts to mitigate the volatile change in
value for our crude oil and refined petroleum products
inventory.
When active, the
fair value of commodity futures contracts was reflected in our
consolidated balance sheets and the related net gain or loss was
recorded within cost of refined products sold in our consolidated
statements of operations. Quoted prices for identical assets or
liabilities in active markets (Level 1) were considered to
determine the fair values for marking to market the financial
instruments at each period end. Commodity transactions
were executed to minimize transaction costs, monitor consolidated
net exposures, and allow for increased responsiveness to changes in
market factors.
At September 30,
2017, we had no futures contracts of refined petroleum products and
crude oil and condensate that were entered as economic
hedges. We also had no derivative instruments that were
reported in our consolidated balance sheets at September 30, 2017
and December 31, 2016.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to
Consolidated Financial Statements
(Continued)
The following table
provides the effect of derivative instruments in our consolidated
statements of operations for the three and nine months ended
September 30, 2017 and 2016:
|
|
|
|
|
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
Statements of Operations Location
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
Cost of refined
products sold
|
$
-
|
$
770,838
|
$
-
|
$
(2,588,734
)
|
(18)
Commitments and Contingencies
Legal Matters
.
GEL Contract-Related Dispute and Final Arbitration
Award
.
See
“Note (1) Organization – Going Concern – Final
Arbitration Award” of this Quarterly Report for disclosures
related to the GEL contract-related dispute and Final Arbitration
Award. In addition, see "Part II, Item 1. Legal Proceedings”
in our Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 2017 as filed with the Securities and Exchange Commission
(the “SEC”) for additional information regarding the
contract related dispute and Final Arbitration
Award.
Veritex Secured Loan Agreement Event of Default
. See “Note (1) Organization
– Going Concern – Veritex Secured Loan Agreement Event
of Default” and “Note (10) Long-Term Debt, Net”
for disclosures related to defaults under secured loan
agreements.
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.
Amended and Restated Operating
Agreement
. See “Note (8) Related Party
Transactions” for additional disclosures related to the
Amended and Restated Operating Agreement.
Financing Agreements
. See
“Note (10) Long-Term Debt, Net” for additional
disclosures related to financing agreements.
Health, Safety and Environmental
Matters
. All our operations and properties are subject to
extensive federal, state, and local environmental, health, and
safety regulations governing, among other things, the generation,
storage, handling, use and transportation of petroleum and
hazardous substances; the emission and discharge of materials into
the environment; waste management; characteristics and composition
of jet fuel and other products; and the monitoring, reporting and
control of greenhouse gas emissions. Our operations also require
numerous permits and authorizations under various environmental,
health, and safety laws and regulations. Failure to obtain and
comply with these permits or environmental, health, or safety laws
generally could result in fines, penalties or other sanctions, or a
revocation of our permits.
Nixon Facility Expansion
.
We
have made and
continue to make capital and efficiency improvements to the Nixon
Facility. Therefore, we incurred and will continue to incur capital
expenditures related to these improvements, which include, among
other things, facility and land improvements and completion of
petroleum storage tanks.
Supplemental Pipeline Bonds
. In
August 2015, we received a letter from the Bureau of Ocean Energy
Management (the “BOEM”) requiring additional
supplemental bonds or acceptable financial assurance of
approximately $4.2 million for existing pipeline rights-of-way. In
July 2016, the BOEM issued Notice to Lessees (“NTL”)
No. 2016-N01 (Requiring Additional Security), which changes the way
that lessees and rights-of-way holders demonstrate financial
strength and reliability to plug and abandon wells, as well as
decommission and remove platforms and pipelines at the end of
production or service activities. The NTL, which changed an earlier
supplemental waiver process to a self-insurance model, became
effective in September 2016. Pursuant to the NTL, the BOEM
requested that lessees submit any relevant information needed for
an overall financial review of the lessees account. The
BOEM indicated that it would use this information to evaluate a
lessees’ ability to carry out its obligations and determine
whether, and/or how much self-insurance a lessee can
use.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Notes to Consolidated
Financial Statements
(Continued)
In October 2016, we
received a letter from the BOEM summarizing the amount required as
additional security on our existing pipeline
rights-of-way. The letter, which is a courtesy and does
not constitute a formal order by the BOEM, requested that we
provide additional supplemental pipeline bonds or acceptable
financial reassurance of approximately $4.6 million. At
September 30, 2017 and December 31, 2016, we maintained
approximately $0.9 million in credit and cash-backed pipeline
rights-of-way bonds issued to the BOEM. Of the five (5)
pipeline rights-of-ways reflected in the BOEM’s October 2016
letter:
(i)
the pipeline associated with one (1)
right-of-way was decommissioned in 1997, and
(ii)
the pipelines associated with three (3)
rights-of-way (Segment Nos. 15635, 13101, and 9428) have been
approved for decommissioning by the Bureau of Safety and
Environmental Enforcement (the “BSEE”); decommissioning
of Segment No. 9428 also requires approval by the U.S. Army Corps
of Engineers, which has not yet been granted.
There can be no
assurance that the BOEM will accept a reduced amount of
supplemental financial assurance or not require additional
supplemental pipeline bonds related to our existing pipeline
rights-of-way. If we are required by the BOEM to provide
significant additional supplemental bonds or acceptable financial
assurance, we may experience a significant and material adverse
effect on our operations, liquidity, and financial
condition.
(19)
Subsequent
Events
Amended GEL Letter
Agreement
. As previously disclosed, on November
1, 2017, LE and GEL extended the date through which GEL has the
right to terminate the GEL Letter Agreement to November 28,
2017. For additional information regarding the Final
Arbitration Award, the GEL Letter Agreement, the Amended GEL Letter
Agreement, and their potential effects on our business, financial
condition and results of operations, see “Note (1)
Organization – Going Concern” and “Note (10)
Long-Term Debt, Net.”
Debt Assumption Agreement
. On September 18, 2017, LEH paid, on
LE’s behalf, certain obligations totaling $3,648,742 to GEL
in connection with the GEL Arbitration and the GEL Letter
Agreement. In exchange for such payments, LE agreed to assume
$3,677,953 of LEH’s existing indebtedness pursuant to the
Debt Assumption Agreement, entered into on November 14, 2017 and
made effective September 18, 2017, by and among LE, LEH and John H.
Kissick.
Sixth
Amendment to Notre Dame Debt
. Pursuant to a Sixth Amendment to the
Notre Dame Debt, entered into on November 14, 2017 and made
effective September 18, 2017, the Notre Dame Debt was amended by
the Additional Principal. The Additional Principal was used to make
payments to GEL in the amount of $3,648,742 in connection with the
GEL Letter Agreement to reduce the balance of the Final Arbitration
Award.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
ITEM 2.
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
In this Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2017 (the Quarterly
Report”), references to “Blue Dolphin,”
“we,” “us” and “our” are to
Blue Dolphin Energy Company and its subsidiaries, unless otherwise
indicated or the context otherwise requires. You should read the
following discussion together with the financial statements and the
related notes included elsewhere in this Quarterly Report, as well
as with the risk factors, financial statements, and related notes
included thereto in our Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 2017 and June 30, 2017, as well as
our Annual Report on Form 10-K for the fiscal year ended December
31, 2016 (the “Annual
Report”).
Forward Looking
Statements
Certain statements
included in this Quarterly Report, including in this
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations” are forward-looking
statements within the meaning of the Private Securities Litigation
Reform Act of 1935. Forward-looking statements represent
management’s beliefs and assumptions based on currently
available information. Forward-looking statements relate to
matters such as our industry, business strategy, goals and
expectations concerning our market position, future operations,
margins, profitability, capital expenditures, liquidity and capital
resources, access to supplies of crude oil and condensate,
commitments and contingencies, and other financial and operating
information. We have used the words “anticipate,”
“assume,” “believe,” “budget,”
“continue,” “could,”
“estimate,” “expect,” “intend,”
“may,” “plan,” “potential,”
“predict,” “project,” “will,”
“future” and similar terms and phrases to identify
forward-looking statements.
Forward-looking
statements reflect our current expectations regarding future
events, results, or outcomes. These expectations may or may not be
realized. Some of these expectations may be based upon assumptions
or judgments that prove to be incorrect. In addition, our business
and operations involve numerous risks and uncertainties, many of
which are beyond our control, which could result in our
expectations not being realized, or materially affect our financial
condition, results of operations and cash flows. Actual
events, results and outcomes may differ materially from our
expectations due to a variety of factors. Although it is not
possible to identify all these factors, they include, among others,
the following and other factors described under the heading
“Risk Factors” in the Annual Report and this Quarterly
Report:
Risks Related to Our Business
and Industry
●
Failure to
reach a settlement agreement with GEL (See “GEL
Contract-Related Dispute and Final Arbitration Award”
below).
●
Inadequate
liquidity to sustain operations due to the unfavorable outcome in
the arbitration of the contract-related dispute with GEL, net
losses, working capital deficits, and other factors, including
crude supply issues tied to access to capital and financial
covenant defaults in secured loan agreements, any of which could
have a material adverse effect on us.
●
Dangers
inherent in oil and gas operations that could cause disruptions and
expose us to potentially significant losses, costs or liabilities
and reduce our liquidity.
●
Geographic
concentration of our assets, which creates a significant exposure
to the risks of the regional economy.
●
Competition from companies having greater
financial and other resources.
●
Laws and
regulations regarding personnel and process safety, as well as
environmental, health, and safety, for which failure to comply may
result in substantial fines, criminal sanctions, permit
revocations, injunctions, facility shutdowns, and/or significant
capital expenditures.
●
Insurance
coverage that may be inadequate or expensive.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
●
Related
party transactions with LEH and its affiliates (including Jonathan
Carroll and Ingleside), which may cause conflicts of
interest.
●
Failure to
comply with certain financial covenants related to certain secured
loan agreements.
●
Our
ability to use net operating loss (“NOL”) carryforwards
to offset future taxable income for U.S. federal income tax
purposes, which are subject to limitation.
●
Terrorist
attacks, cyber-attacks, threats of war, or actual war may
negatively affect our operations, financial condition, results of
operations, and cash flows.
Risks Related to Our Refinery
Operations Business Segment
●
A
determination by management that there is, and the report of our
independent registered public accounting firm that expresses,
substantial doubt about our ability to continue as a going
concern.
●
Volatility
of refining margins.
●
Volatility
of crude oil, other feedstocks, refined petroleum products, and
fuel and utility services.
●
Our
ability to acquire sufficient levels of crude oil on favorable
terms to operate the Nixon Facility.
●
Refinery
downtime, which could result in lost margin opportunity, increased
maintenance costs, increased inventory, and a reduction in cash
available for payment of our obligations and to which we are
particularly vulnerable because all our refining operations are
conducted at a single facility.
●
Capital
needs for which our internally generated cash flows and other
sources of liquidity may not be adequate.
●
Our
dependence on LEH and its affiliates for financing and management
of our properties.
●
Loss of
executive officers or key employees, as well as a shortage of
skilled labor or disruptions in our labor force, which may make it
difficult to maintain productivity.
●
Loss of
market share by a key customer or consolidation among our customer
base.
●
Failure to
grow or maintain the market share for our refined petroleum
products.
●
Our
reliance on third-parties for the transportation of crude oil and
condensate into and refined petroleum products out of the Nixon
Facility.
●
Interruptions in the supply of crude oil and
condensate sourced in the Eagle Ford Shale.
●
Changes in
the supply/demand balance in the Eagle Ford Shale that could result
in lower margins on refined petroleum products.
●
Regulation
of greenhouse gas emissions, which could increase our operational
costs and reduce demand for our products.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Risks Related to Our
Pipelines and Oil and Gas Properties
●
Required
increases in bonds or other sureties to maintain compliance with
regulatory requirements, which could significantly impact our
liquidity and financial condition.
●
More
stringent regulatory requirements related to asset retirement
obligations (“AROs”), which could significantly
increase our estimated future AROs.
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.
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, legal and
administrative fees and court costs to GEL in the aggregate amount
of approximately $31.3 million.
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.
GEL could have
terminated the GEL Letter Agreement on the 45
th
day of the
Continuance Period, or November 1, 2017, if GEL determined, in its
sole discretion, that settlement discussions between the parties
were not advancing to an acceptable resolution. As
previously disclosed, on November 1, 2017, LE and GEL amended the
GEL Letter Agreement to extend the date through which GEL has the
right to terminate the GEL Letter Agreement to November 28,
2017. The Amended GEL Letter Agreement 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. If we 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 we likely would be required to seek protection under bankruptcy
laws.
Veritex Community
Bank, as successor in interest to Sovereign Bank by merger,
delivered to obligors notices of default under secured loan
agreements with Veritex, stating the 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 likely would 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 September
30, 2017 due to existing or potential 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.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
In addition to the
matters described in the previous paragraphs, 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.
Company Overview
Blue Dolphin is
primarily an independent refiner and marketer of petroleum
products. Our primary asset is a 15,000-bpd crude oil
and condensate processing facility that is in Nixon, Texas (the
“Nixon Facility”). As part of our refinery
business segment, we also conduct petroleum storage and terminaling
operations under third-party lease agreements at the Nixon
Facility. We also own pipeline assets and have leasehold
interests in oil and gas wells. The pipelines and oil
and gas wells are inactive. We maintain a website at
http://www.blue-dolphin-energy.com
. Information
on or accessible through our website is not incorporated by
reference in or otherwise made a part of this Quarterly
Report.
Major Influences on Results of
Operations
As a margin-based
business, our refinery operations are primarily affected by the per
bbl price differential between crude oil and condensate and refined
petroleum products, our product slate, and refinery
downtime.
Feedstock and Product per Bbl
Price Differentials
The prices of crude
oil and refined petroleum products are the most significant driver
of margins, and they have historically been subject to wide
fluctuations. Our cost to acquire crude oil and condensate and the
price for which our refined petroleum products are ultimately sold
depend on the economics of supply and demand. Supply and demand are
affected by numerous factors, most, if not all, of which are beyond
our control, including:
●
Domestic
and foreign market conditions, political affairs, and economic
developments;
●
Import
supply levels and export opportunities;
●
Existing
domestic inventory levels;
●
Operating
and production levels of competing refineries;
●
Expansion
and/or upgrades of competitors’
facilities;
●
Governmental regulations (e.g., mandated
renewable fuels standards, proposed climate change laws and
regulations, and increased mileage standards for
vehicles);
●
Availability of and access to transportation
infrastructure;
●
Availability of competing fuels (e.g.,
renewables); and
For the Current
Three Months, the average per bbl price differential between crude
oil and condensate and refined petroleum products was $6.46
compared to $2.01 for the three months ended September 30, 2016
(the “Prior Three Months”), reflecting an increase of
$4.45. Our gross profit increased from $2,998,832 in the
Prior Three Months to $8,113,265 in the Current Three Months,
reflecting an increase of $5,114,433. The increase
between the periods was primarily because of improved margins on
refined petroleum products.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
For the nine months
ended September 30, 2017 (the “Current Nine Months”),
the average per bbl price differential between crude oil and
condensate and refined petroleum products was $3.02 compared to
$0.42 for the nine months ended September 30, 2016 (the
“Prior Nine Months”), reflecting an increase of
$2.60. Our gross profit increased from $2,926,793 in the
Prior Nine Months to $11,655,896 in the Current Nine Months,
reflecting an increase of $8,729,103. The increase
between the periods was primarily because of improved margins on
refined petroleum products.
Product Slate
Management
periodically determines whether to change product mix, as well as
maintain, increase, or decrease inventory levels based on various
factors. These factors include the crude oil pricing
market in the U.S. Gulf Coast region, the refined petroleum
products market in the same region, the relationship between these
two markets, fulfilling contract demands, and other factors that
may impact our operations, financial condition, and cash
flows.
Refinery
Downtime
The safe and
reliable operation of the Nixon Facility is key to our financial
performance and results of operations, and we are particularly
vulnerable to disruptions in our operations because all our
refining operations are conducted at a single facility. Although
operating at anticipated levels, the Nixon Facility is still in a
recommissioning phase and may require unscheduled downtime for
unanticipated reasons, including maintenance and repairs, voluntary
regulatory compliance measures, or cessation or suspension by
regulatory authorities.
Occasionally, the
Nixon Facility experiences a temporary shutdown due to power
outages from high winds and thunderstorms. In such cases, we must
initiate a standard refinery start-up process, which can last
several days. 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.
Key Relationships
Relationship with
LEH
We are currently
party to a variety of agreements with LEH, including an Amended and
Restated Operating Agreement, a Jet Fuel Sales Agreement, a Loan
and Security Agreement, an Amended and Restated Promissory Note,
and a Debt Assumption Agreement. In addition, we
currently rely on advances from LEH and its affiliates (including
Jonathan Carroll) to fund our working capital requirements. There
can be no assurances that LEH and its affiliates will continue to
fund our working capital requirements. (See “Part
I, Item 1. Financial Statements – Note (8) Related Party
Transactions” for disclosures related to agreements that we
have in place with LEH.)
Relationship with Crude
Supplier
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 new 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 our
financial stability. However, there can be no assurance
that our 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 plan. If our plan
is unsuccessful, it could affect our ability to acquire adequate
supplies of crude oil and condensate under the existing contract 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.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Results of
Operations
Effective January 1,
2017, we began reporting a single business segment – Refinery
Operations. Business activities related to our Refinery
Operations business segment are conducted at the Nixon
Facility. Due to their small size, amounts associated
with Pipeline Transportation operations for the Current Three
Months and Current Nine Months were reclassified to Corporate and
Other. Pipeline Transportation operations diminished significantly
as services to third-parties ceased and third-party wells along our
pipeline corridor were permanently abandoned.
In this Results of
Operations section, we review:
●
Definitions of key financial performance
measures used by management;
●
Consolidated results (reflect financial results
for our Refinery Operations business segment and Corporate and
Other);
●
Non-GAAP
financial measures; and
●
Refinery
Operations business segment results.
Remainder of Page
Intentionally Left Blank
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
9/30/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
GLOSSARY OF SELECTED
FINANCIAL AND PERFORMANCE MEASURES
Management uses GAAP
and certain non-GAAP performance measures to assess our results of
operations. Certain performance measures used by management to
assess our operating results and the effectiveness of our business
segment are considered non-GAAP performance measures. These
performance measures may differ from similar calculations used by
other companies within the petroleum industry, thereby limiting
their usefulness as a comparative measure.
We refer to certain
refinery throughput and production data in the explanation of our
period over period changes in results of operations. For
our consolidated results, we refer to our consolidated statements
of operations in the explanation of our period over period changes
in results of operations.
Below are definitions of key financial
performance measures used by management:
Adjusted Earnings
Before Interest, Income Taxes and Depreciation
(“EBITDA”)
.
Reflects EBITDA excluding
the JMA Profit Share.
-
Refinery Operations
Adjusted EBITDA
. Reflects adjusted EBITDA for our refinery
operations business segment.
-
Total Adjusted
EBITDA
.
Reflects
adjusted EBITDA for our refinery operations business segment, as
well as corporate and other.
Capacity
Utilization Rate
. A percentage measure that indicates the
amount of available capacity that is being used in a refinery or
transported through a pipeline. With respect to the
Nixon Facility, the rate is calculated by dividing total refinery
throughput or total refinery production on a bpd basis by the total
capacity of the Nixon Facility (currently 15,000 bpd).
Cost of Refined
Products Sold
.
Primarily includes purchased crude oil and condensate costs, as
well as transportation, freight and storage costs.
Depletion,
Depreciation and Amortization
. Represents property and
equipment, as well as intangible assets that are depreciated or
amortized based on the straight-line method over the estimated
useful life of the related asset.
Downtime
.
Scheduled and/or unscheduled periods in which the Nixon Facility is
not operating. Downtime may occur for a variety of
reasons, including bad weather, power failures, preventive
maintenance, equipment inspection, equipment repair due to
mechanical failure, voluntary regulatory compliance measures,
cessation or suspension by regulatory authorities, and inventory
management.
Easement, Interest
and Other Income
.
Reflects land easement fees received from FLNG Land II, Inc., a
Delaware corporation (“FLNG”), pursuant to a Master
Easement Agreement; fees recognized monthly as earned and recorded
as land easement revenue within other income.
EBITDA
.
Reflects earnings before: (i) interest income (expense), (ii)
income taxes, and (iii) depreciation and amortization.
-
Refinery Operations
EBITDA
. Reflects EBITDA for our refinery operations business
segment.
-
Total
EBITDA
. Reflects EBITDA for our refinery operations business
segment, as well as corporate and other.
General and
Administrative Expenses
.
Primarily include corporate costs,
such as accounting and legal fees, office lease expenses, and
administrative expenses.
Gross
Profit
.
Calculated as total revenue less
cost of refined products sold.
Income Tax
Expense
.
Includes
federal and state taxes, as well as deferred taxes, arising from
temporary differences between income for financial reporting and
income tax purposes.
JMA Profit
Share
. Represents the GEL Profit Share plus the Performance
Fee for the period under the Joint Marketing Agreement; an indirect
operating expense. If Gross Profits were positive, then the JMA
Profit Share reflected an expense. If Gross Profits were
negative, then the JMA Profit Share reflected a
credit.
Net Income
.
Represents total revenue from operations less total cost of
operations, total other expense, and income tax
expense.
Operating
Days
. Represents the number of days in a period in which the
Nixon Facility operated. Operating days is calculated by
subtracting downtime in a period from calendar days in the same
period.
Other Income
(Expense)
. Reflects working capital loan
interest, guaranty fees paid to Jonathan Carroll, expensed interest
related to long-term debt, and non-recurring income
items.
Other Operating
Expenses
. Represents costs associated with our pipeline
assets and leasehold interests in oil and gas
properties.
Refinery Operating
Expenses
.
Direct
operating expenses of the Nixon Facility, including direct costs of
labor, maintenance materials and services, chemicals and catalysts
and utilities. Includes fees paid to: (i) LEH to manage
and operate the Nixon Facility pursuant to the Amended and Restated
Operating Agreement and (ii) Ingleside Crude, LLC to lease
petroleum storage tanks to meet periodic, additional storage needs
under the Amended and Restated Tank Lease Agreement.
Revenue from
Operations
. Primarily consists of refined petroleum product
sales, but also includes tank rental revenue. Excise and other
taxes that are collected from customers and remitted to
governmental authorities are not included in
revenue. Other revenue relates to fees received from
pipeline transportation services, which ceased in
2016.
Total Refinery
Production
. Refers to the volume processed as output through
the Nixon Facility. Refinery production includes finished petroleum
products, such as jet fuel and exportable low-sulfur diesel, and
intermediate petroleum products, such as LPG, naphtha, HOBM and
AGO.
Total Refinery
Throughput
.
Refers
to the volume processed as input through the Nixon
Facility. Refinery throughput includes crude oil and
condensate and other feedstocks.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Consolidated
Results
Current Three Months Compared to Prior
Three Months
.
Total Revenue from Operations
. For the
Current Three Months, we had total revenue from operations of
$66,899,092 compared to total revenue from operations of
$54,688,306 for the Prior Three Months. The approximate
22% increase in total revenue from operations between the periods
was primarily the result of higher commodity prices for refined
petroleum products in the Current Three Months compared to the
Prior Three Months.
Cost of Refined Products Sold
. Cost of
refined products sold was $58,785,827 for the Current Three Months
compared to $51,689,474 for the Prior Three Months. The
approximate 14% increase in cost of refined products sold was
primarily the result of higher crude oil prices in the Current
Three Months compared to the Prior Three Months.
Gross Profit
. For the Current Three
Months, gross profit totaled $8,113,265 compared to gross profit of
$2,998,832 for the Prior Three Months. The $5,114,433
increase between the periods related to higher commodity prices for
refined petroleum products in the Current Three Months compared to
the Prior Three Months.
Refinery Operating
Expenses
. We recorded refinery operating expenses
of $1,758,005 in the Current Three Months compared to $3,153,646 in
the Prior Three Months, a decrease of 44%. Refinery
operating expenses per bbl of throughput were $1.53 in the Current
Three Months compared to $2.77 in the Prior Three
Months. The $1.24 decrease in refinery operating
expenses per bbl of throughput between the periods was the result
of: (i) significantly lower refinery operating expenses under the
Amended and Restated Operating Agreement, which was restructured
following cessation of crude supply and marketing activities under
the Crude Supply Agreement and Joint Marketing Agreement with GEL
and (ii) a decrease in off-site tank leasing expense under an
Amended and Restated Tank Lease Agreement. (See “Part I, Item
1. Financial Statements – Note (8) Related Party
Transactions” for additional disclosures related to
components of refinery operating expenses, the Amended and Restated
Operating Agreement, and the Amended and Restated Tank Lease
Agreement.)
JMA Profit Share.
For the
Current Three Months, the JMA Profit Share was $0 compared to an
expense of $965,627 for the Prior Three
Months. Elimination of the JMA Profit Share between the
periods was the result of cessation of marketing activities under
the Joint Marketing Agreement. (See “Part I, Item
1. Financial Statements – Note (18) Commitments and
Contingencies – Legal Matters” for further discussion
related to the Joint Marketing Agreement, JMA Profit Share, Gross
Profits and the contract-related dispute with GEL.)
General and Administrative Expenses
. We
incurred general and administrative expenses of $1,239,813 in the
Current Three Months compared to $891,210 in the Prior Three
Months. The 39% increase in general and administrative
expenses in the Current Three Months compared to the Prior Three
Months primarily related to an increase in legal fees associated
with the contract-related dispute with GEL.
Depletion, Depreciation and
Amortization
. We recorded depletion, depreciation
and amortization expenses of $455,437 in the Current Three Months
compared to $504,719 in the Prior Three Months. The
approximate 10% decrease in depletion, depreciation and
amortization expenses for the Current Three Months compared to the
Prior Three Months was primarily due to lower depreciation related
to our pipeline assets.
Other Income (Expense).
We
recorded $574,678 in other expense
in the Current Three Months
compared to $327,819 in other expense in the Prior Three
Months. The significant increase in other expense
between the periods primarily related to a decrease in easement
income and an increase in working capital loan
interest.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Income Tax Benefit
. We
recognized an income tax benefit of $0 in the Current Three Months
compared to $1,034,798 in the Prior Three Months. Income
tax benefit in the Prior Three Months primarily related to deferred
federal income taxes. We recorded a full valuation
allowance against deferred tax assets as of September 30, 2017 and
December 31, 2016 (See “Part I, Item 1. Financial Statements
– Note (15) Income Taxes” for additional disclosures
related to income taxes.)
Net Income (Loss)
. For the
Current Three Months, we reported income of $3,945,519, or income
of $0.36 per share, compared to a net loss of $1,938,551, or loss
of $0.19 per share, for the Prior Three Months. The $0.55 per share
improvement between the periods was primarily the result of
favorable refining margins.
Current Nine Months Compared to Prior
Nine Months
.
Total Revenue from Operations
. For the
Current Nine Months, we had total revenue from operations of
$176,841,172 compared to total revenue from operations of
$128,243,042 for the Prior Nine Months. The approximate
38% increase in total revenue from operations between the periods
was primarily the result of higher commodity prices for refined
petroleum products and a 7% increase in sales volume in the Current
Nine Months compared to the Prior Nine Months. Refinery
production increased due to improved refinery
uptime. The Nixon Facility experienced significant
downtime for the Prior Nine Months due to the contract-related
dispute with GEL.
Cost of Refined Products Sold
. Cost of
refined products sold was $165,185,276 for the Current Nine Months
compared to $125,316,249 for the Prior Nine Months. The
approximate 32% increase in cost of refined products sold was the
result of higher commodity prices for crude oil and increased sales
volume in the Current Nine Months compared to the Prior Nine
Months.
Gross Profit
. For the Current Nine
Months, gross profit totaled $11,655,896 compared to gross profit
of $2,926,793 for the Prior Nine Months. The $8,729,103
increase between the periods related to favorable refining margins
and increased sales volume in the Current Nine Months compared to
the Prior Nine Months.
Refinery Operating
Expenses
. We recorded refinery operating expenses
of $6,222,771 in the Current Nine Months compared to $9,468,409 in
the Prior Nine Months, a decrease of approximately
34%. Refinery operating expenses per bbl of throughput
were $1.93 in the Current Nine Months compared to $3.12 in the
Prior Nine Months. The $1.19 decrease in refinery
operating expenses per bbl of throughput between the periods was
the result of: (i) significantly lower refinery operating expenses
under the Amended and Restated Operating Agreement, which was
restructured following cessation of crude supply and marketing
activities under the Crude Supply Agreement and Joint Marketing
Agreement with GEL and (ii) a decrease in off-site tank leasing
expense under an Amended and Restated Tank Lease Agreement. (See
“Part I, Item 1. Financial Statements – Note (8)
Related Party Transactions” for additional disclosures
related to components of refinery operating expenses, the Amended
and Restated Operating Agreement, and the Amended and Restated Tank
Lease Agreement.)
JMA Profit Share.
For the
Current Nine Months, the JMA Profit Share was $0 compared to an
expense of $392,062 for the Prior Nine
Months. Elimination of the JMA Profit Share between the
periods was the result of cessation of marketing activities under
the Joint Marketing Agreement. (See “Part I, Item
1. Financial Statements – Note (18) Commitments and
Contingencies – Legal Matters” for further discussion
related to the Joint Marketing Agreement, JMA Profit Share, Gross
Profits and the contract-related dispute with GEL.)
Arbitration Award and Associated
Fees
. For the Current Nine Months, legal
settlement and fees totaled $24,338,628 compared to $0 for the
Prior Nine Months. Legal settlement and fees were
associated with the Final Arbitration Award.
General and Administrative Expenses
. We
incurred general and administrative expenses of $2,854,294 in the
Current Nine Months compared to $1,503,533 in the Prior Nine
Months. The nearly 90% increase in general and
administrative expenses in the Current Nine Months compared to the
Prior Nine Months primarily related to an increase in legal fees
associated with the contract-related dispute with GEL.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Depletion, Depreciation and
Amortization
. We recorded depletion, depreciation
and amortization expenses of $1,355,780 in the Current Nine Months
compared to $1,415,519 in the Prior Nine Months. The
approximate 4% decrease in depletion, depreciation and amortization
expenses for the Current Nine Months compared to the Prior Nine
Months was primarily due to lower depreciation related to our
pipeline assets.
Other Income (Expense).
We
recorded $207,149 in other income in the Current Nine Months
compared to $889,425 of other expense in the Prior Nine
Months. The improvement in other income between the
periods related to a gain on the sale of land to FLNG in the first
quarter of 2017, which was offset by interest expense related to
working capital loan interest, long-term debt interest expense, and
guaranty fee expense. In February 2017, BDPL sold
approximately 15 acres of property located in Brazoria County,
Texas to FLIQ Common Facilities, LLC, an affiliate of
FLNG. In conjunction with the sale of real estate, the
FLNG Easements were terminated.
Income Tax Benefit
. We
recognized an income tax benefit of $0 in the Current Nine Months
compared to $3,735,040 in the Prior Nine Months. Income
tax benefit in the Prior Nine Months primarily related to deferred
federal income taxes. We recorded a full valuation
allowance against deferred tax assets as of September 30, 2017 and
December 31, 2016 (See “Part I, Item 1. Financial Statements
– Note (15) Income Taxes” for additional disclosures
related to income taxes.)
Net Loss
. For the Current
Nine Months, we reported a net loss of $23,307,055, or a loss of
$2.19 per share, compared to net loss of $7,250,371, or loss of
$0.69 per share, for the Prior Nine Months. The $1.50
per share increase in net loss between the periods was primarily
the result of the Final Arbitration Award in the Current Nine
Months compared to the Prior Nine Months.
Remainder of Page
Intentionally Left Blank
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Non-GAAP Financial
Measures
To supplement our
consolidated results, management uses EBITDA, a non-GAAP financial
measures, to help investors evaluate our ongoing operating results
and allow for greater transparency in reviewing our overall
financial, operational and economic performance. EBITDA is
reconciled to GAAP-based results below. EBITDA should not be
considered an alternative for GAAP results. EBITDA is provided to
enhance an overall understanding of our financial performance for
the applicable periods and is an indicator management believes is
relevant and useful. EBITDA may differ from similar calculations
used by other companies within the petroleum industry, thereby
limiting its usefulness as a comparative measure. (See “Part
I, Item 1. Financial Statements” for comparative GAAP
results.)
EBITDA Current Three Months Compared
to Prior Three Months
.
Refinery Operations
EBITDA.
Refinery operations EBITDA for the
Current Three Months was $5,442,546 compared to a loss of
$1,792,422 for the Prior Three Months. The significant
increase in refinery operations EBITDA between the periods was
primarily the result of improved margins on refined petroleum
products in the Current Three Months.
EBITDA Reconciliation to GAAP –
Three Month Periods
.
|
|
Three Months Ended September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
operations
|
$
66,899,092
|
$
-
|
$
66,899,092
|
$
54,668,780
|
$
19,526
|
$
54,688,306
|
|
Less: cost of
operations
(1)
|
(61,456,546
)
|
(466,912
)
|
(61,923,458
)
|
(55,495,575
)
|
(367,915
)
|
(55,863,490
)
|
|
Other non-interest
income
(2)
|
-
|
-
|
-
|
-
|
156,396
|
156,396
|
|
Less: JMA
Profit Share
(3)
|
-
|
-
|
-
|
(965,627
)
|
-
|
(965,627
)
|
|
EBITDA
|
$
5,442,546
|
$
(466,912
)
|
$
4,975,634
|
$
(1,792,422
)
|
$
(191,993
)
|
$
(1,984,415
)
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and
|
|
|
|
|
|
|
|
amortization
|
|
|
(455,437
)
|
|
|
(504,719
)
|
|
Interest expense,
net
|
|
|
(574,678
)
|
|
|
(484,215
)
|
|
|
|
|
|
|
|
|
Income (loss) before
income taxes
|
|
3,945,519
|
|
|
(2,973,349
)
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
-
|
|
|
1,034,798
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
|
$
3,945,519
|
|
|
$
(1,938,551
)
|
|
(1)
|
Operation cost
within the Refinery Operations segment includes related general and
administrative expenses. Operation cost within Corporate
and Other includes general and administrative expenses associated
with corporate maintenance costs (such as accounting fees, director
fees, and legal expense), as well as expenses associated with our
pipeline assets and oil and/or gas leasehold interests (such as
accretion and impairment expenses).
|
|
(2)
|
Other non-interest
income reflects FLNG easement revenue.
|
|
(3)
|
The JMA Profit Share
represents the GEL Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement, under which
marketing activities have ceased. (See “Part I,
Item 1. Financial Statements – Note
(1) Organization
– Going Concern
– Final
Arbitration Award
” for further discussion of
the contract-related dispute with GEL.)
|
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
EBITDA Current Nine Months Compared to
Prior Nine Months
.
Refinery Operations
EBITDA.
Refinery operations EBITDA for the
Current Nine Months was a loss of $20,865,262 compared to a loss of
$7,673,422 for the Prior Nine Months. The significant
decrease in refinery operations EBITDA between the periods was
primarily the result of the Final Arbitration Award in the Current
Nine Months.
EBITDA Reconciliation to GAAP –
Nine Month Periods
.
|
|
Nine Months Ended September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
operations
|
$
176,841,172
|
$
-
|
$
176,841,172
|
$
128,171,177
|
$
71,865
|
$
128,243,042
|
|
Less: cost of
operations
(1)
|
(197,706,434
)
|
(1,293,162
)
|
(198,999,596
)
|
(135,452,537
)
|
(1,078,910
)
|
(136,531,447
)
|
|
Other non-interest
income
(2)
|
-
|
2,216,251
|
2,216,251
|
-
|
412,061
|
412,061
|
|
Less: JMA
Profit Share
(3)
|
-
|
-
|
-
|
(392,062
)
|
-
|
(392,062
)
|
|
EBITDA
|
$
(20,865,262
)
|
$
923,089
|
$
(19,942,173
)
|
$
(7,673,422
)
|
$
(594,984
)
|
$
(8,268,406
)
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and
|
|
|
|
|
|
|
|
amortization
|
|
|
(1,355,780
)
|
|
|
(1,415,519
)
|
|
Interest expense,
net
|
|
|
(1,999,760
)
|
|
|
(1,301,486
)
|
|
|
|
|
|
|
|
|
|
Loss before income
taxes
|
|
|
(23,297,713
)
|
|
|
(10,985,411
)
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
-
|
|
|
3,735,040
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
$
(23,297,713
)
|
|
|
$
(7,250,371
)
|
|
(1)
|
Operation cost
within the Refinery Operations segment includes related general and
administrative expenses and the arbitration award and associated
fees. Operation cost within Corporate and Other includes
general and administrative expenses associated with corporate
maintenance costs (such as accounting fees, director fees, and
legal expense), as well as expenses associated with our pipeline
assets and oil and/or gas leasehold interests (such as accretion
and impairment expenses).
|
|
(2)
|
Other non-interest
income reflects FLNG easement revenue.
|
|
(3)
|
The JMA Profit Share
represents the GEL Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement, under which
marketing activities have ceased. (See “Part I,
Item 1. Financial Statements – Note
(1) Organization
– Going Concern
– Final
Arbitration Award
” for further discussion of
the contract-related dispute with GEL.)
|
Refinery Operations Business
Segment Results
During the Current
Three Months, the average per bbl price differential between crude
oil and condensate and refined petroleum products was $6.46
compared to $2.01 for the Prior Three Months, reflecting an
increase of $4.45. Our gross profit increased from
$2,998,832 in the Prior Three Months to $8,113,265 in the Current
Three Months, reflecting an increase of $5,114,433. The
increase between the periods was primarily due to favorable
refining margins.
During the Current
Nine Months, the average per bbl price differential between crude
oil and condensate and refined petroleum products was $3.02
compared to $0.42 for the Prior Nine Months, reflecting an increase
of $2.60. Our gross profit increased from $2,926,793 in
the Prior Nine Months to $11,655,896 in the Current Nine Months,
reflecting an increase of $8,729,103. The increase
between the periods was primarily due to favorable refining margins
and increased sales volume.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Refinery Throughput and Production
Data
.
Following
are refinery operational metrics for the Nixon
Facility:
|
|
Three Months Ended September
30,
|
Nine Months Ended September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar
Days
|
92
|
92
|
273
|
274
|
|
Refinery
downtime
|
(3
)
|
(1
)
|
(17
)
|
(30
)
|
|
Operating
Days
|
89
|
91
|
256
|
244
|
|
|
|
|
|
|
|
Total refinery
throughput (bbls)
|
1,145,484
|
1,139,458
|
3,228,144
|
3,034,257
|
|
Operating days
:
|
|
|
|
|
|
bpd
|
12,871
|
12,522
|
12,610
|
12,435
|
|
Capacity utilization
rate
|
85.8
%
|
83.5
%
|
84.1
%
|
82.9
%
|
|
Calendar days
:
|
|
|
|
|
|
bpd
|
12,451
|
12,385
|
11,825
|
11,074
|
|
Capacity utilization
rate
|
83.0
%
|
82.6
%
|
78.8
%
|
73.8
%
|
|
|
|
|
|
|
|
Total refinery
production (bbls)
|
1,110,734
|
1,106,415
|
3,127,391
|
2,948,821
|
|
Operating days
:
|
|
|
|
|
|
bpd
|
12,480
|
12,158
|
12,216
|
12,085
|
|
Capacity utilization
rate
|
83.2
%
|
81.1
%
|
81.4
%
|
80.6
%
|
|
Calendar days
:
|
|
|
|
|
|
bpd
|
12,073
|
12,026
|
11,456
|
10,762
|
|
Capacity utilization
rate
|
80.5
%
|
80.2
%
|
76.4
%
|
71.7
%
|
|
Note:
|
The difference
between total refinery throughput (volume processed as input) and
total refinery production (volume processed as output) represents
refinery fuel use and loss.
|
In the Current Three
Months, the Nixon Facility experienced 3 days of refinery downtime
related to repairs and Hurricane Harvey. In the Prior
Three Months, the Nixon Facility experienced 1 day of refinery
downtime due to maintenance. Total refinery throughput
bbls and total refinery production bbls were flat between the
periods.
In the Current Nine
Months, the Nixon Facility experienced 17 days of refinery downtime
related to throughput management, repairs, and Hurricane
Harvey. In the Prior Nine Months, the Nixon Facility
experienced 30 days of refinery downtime primarily due to the
contract-related dispute with GEL. Despite the
significant downtime in the Current Nine Months, total refinery
throughput bbls and total refinery production bbls increased
approximately 6% compared to the Prior Nine Months because of
improved refinery uptime associated with crude oil and condensate
delivery.
Refined Petroleum Product Sales
Summary
.
(See “Part I,
Item 1. Financial Statements - Note (13) Concentration of
Risk” for a discussion of refined petroleum product
sales.)
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Refined Petroleum Products Economic
Hedges
.
During 2017, we
began selling all our jet fuel immediately following production,
which minimizes inventory, improves cash flow, and reduces
commodity risk. Previously, Genesis/GEL used commodity
futures contracts to mitigate the volatile change in value for
certain of our refined petroleum products inventory.
We had no open
commodity contracts in the Current Three Months and Current Nine
Months. For the Prior Three Months, our refinery
operations business segment recognized a gain of $2,299,678 on
settled transactions and a loss of $1,528,840 on the change in
value of open contracts from June 30, 2016 to September 30, 2016.
For the Prior Nine Months, our refinery operations business segment
recognized a loss of $1,445,244 on settled transactions and a loss
of $1,143,490 on the change in value of open contracts from
December 31, 2015 to September 30, 2016.
Liquidity and Capital
Resources
Overview
.
Historically, we
relied on the profit share distribution and operations payments
under a Joint Marketing Agreement with GEL, as well as LEH, to fund
our liquidity needs. As disclosed elsewhere in this
Quarterly Report, beginning in the second quarter of 2016, LE
experienced an adverse change in its relationship with Genesis/GEL
involving a contract-related dispute. This shift in the
relationship 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. Combined with decreased commodity prices
throughout 2016, our resultant financial state raised substantial
doubt about our ability to continue as a going concern, which doubt
has increased because of the Final Arbitration
Award. (As discussed elsewhere within this
“Liquidity and Capital Resources” section, management
has determined that there is substantial doubt about our ability to
continue as a going concern due to consecutive quarterly net
losses, inadequate working capital, the Final Arbitration Award,
crude supply issues tied to access to capital, and defaults under
secured loan agreements. See “Part I, Item 1. Financial
Statements – Note (1) Organization – Going
Concern” for additional discussion related to going
concern.)
As discussed
elsewhere in this Quarterly Report, on August 11, 2017, the
arbitrator delivered the Final Arbitration Award in the GEL
Arbitration. Among other matters, the Final Arbitration
Award awarded damages, legal and administrative fees and court
costs to GEL in the aggregate amount of approximately $31.3
million. LE expects that it will be unable to pay the amounts
awarded to GEL in full or in any substantial part. 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 of 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.
GEL could have
terminated the GEL Letter Agreement on the 45
th
day of the
Continuance Period, or November 1, 2017, if GEL determined, in its
sole discretion, that settlement discussions between the parties
were not advancing to an acceptable resolution. As
previously disclosed, on November 1, 2017, LE and GEL amended the
GEL Letter Agreement to extend the date through which GEL has the
right to terminate the GEL Letter Agreement to November 28,
2017. The Amended GEL Letter Agreement 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.
Veritex 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 likely would
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 September 30, 2017 due to existing or
potential 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.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
We can provide no
assurance as to whether negotiations with GEL will result in a
settlement or as to 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 we likely would be required to seek protection under
bankruptcy laws.
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 new 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.
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 Current Nine Months, we continued
aggressive actions to improve operations and liquidity. We began
selling all our jet fuel immediately following production, which
minimizes inventory, improves cash flow, and reduces commodity
risk/exposure. We also completed construction of several new
petroleum storage tanks at the Nixon
Facility. Increasing petroleum storage capacity: (i)
assists with de-bottlenecking the facility, (ii) supports increased
refinery throughput up to approximately 17,000 bpd, and (iii)
provides an opportunity to generate additional tank rental revenue
by leasing to third-parties. Additional ongoing efforts
to improve operations and liquidity include restructuring customer
contracts on more favorable terms as they come up for
renewal. Management believes that it is taking the
appropriate steps to improve our financial stability. However,
there can be no assurance that our 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 plan.
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 new 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.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Management believes
that it is taking the appropriate steps to improve our financial
stability. However, there can be no assurance that our
plan will be successful, LEH and its affiliates (including Jonathan
Carroll) will continue to fund our working capital needs, or that
we will be able to obtain additional financing on commercially
reasonable terms or at all. If our 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 plan and
could have a material adverse effect on our ability to procure
adequate amounts and 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.
Cash Flow
.
Our cash flow
from operations for the periods indicated was as
follows:
|
|
Three Months Ended September
30,
|
Nine Months Ended September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from
operations
|
|
|
|
|
|
Adjusted income (loss)
from operations
|
$
4,504,921
|
$
(879,483
)
|
$
(21,600,038
)
|
$
(8,335,348
)
|
|
Change in assets and
current liabilities
|
(5,673,761
)
|
(5,493,430
)
|
15,464,667
|
3,657,961
|
|
|
|
|
|
|
|
Total cash inflows
(outflows) from operations
|
(1,168,840
)
|
(6,372,913
)
|
(6,135,371
)
|
(4,677,387
)
|
|
|
|
|
|
|
|
Cash inflows
(outflows)
|
|
|
|
|
|
Proceeds from issuance
of debt
|
3,677,953
|
6,898,931
|
3,677,953
|
6,898,931
|
|
Payments on
debt
|
(265,063
)
|
(469,541
)
|
(1,120,267
)
|
(1,414,406
)
|
|
Net activity on
related-party debt
|
(2,288,717
)
|
-
|
967,977
|
-
|
|
Capital
expenditures
|
(369,518
)
|
(4,182,747
)
|
(1,777,219
)
|
(11,255,725
)
|
|
|
|
|
|
|
|
Total cash inflows
(outflows)
|
754,655
|
2,246,643
|
1,748,444
|
(5,771,200
)
|
|
|
|
|
|
|
|
Total change in cash
flows
|
$
(414,185
)
|
$
(4,126,270
)
|
$
(4,386,927
)
|
$
(10,448,587
)
|
For the Current
Three Months, we experienced negative cash flow from operations of
$1,168,840 compared to negative cash flow from operations of
$6,372,913 for the Prior Three Months. The $5,204,073 improvement
in cash flow from operations between the periods was primarily the
result of more favorable refining margins and payment of accounts
payable at a slower rate in the Current Three Months compared to
the Prior Three Months.
For the Current Nine
Months, we experienced negative cash flow from operations of
$6,135,371 compared to negative cash flow from operations of
$4,677,387 for the Prior Nine Months. The $1,457,984 decline in
cash flow from operations between the periods was primarily the
result of an increase in accounts receivable.
Working Capital
.
During the Current
Three Months, net cash used in financing activities totaled
$1,124,173 compared to net cash provided by financing activities
totaling $6,429,390 in the Prior Three Months. For the
Current Nine Months, net cash provided by financing activities
totaled $3,525,663 compared to net cash provided by financing
activities totaling $5,484,525. Working capital provided
by financing activities represented advances from LEH and its
affiliates (including Jonathan Carroll) under promissory
notes. (See “Part I, Item 1. Financial Statements
– Note (8) Related Party Transactions and Note (10) Long-Term
Debt, Net,” as well as “Contractual Obligations –
Related Party” within the Liquidity and Capital Resources
section for additional disclosures with respect to related party
promissory notes.)
We had a working
capital deficit of $67,084,694 at September 30, 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
$27,328,649 at September 30, 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.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
As discussed
elsewhere within this “Liquidity and Capital Resources”
section, the contract-related dispute with GEL and the Final
Arbitration Award has affected our ability to obtain working
capital through financing. Although LE is currently in
settlement discussions with GEL, we expect this to continue for the
foreseeable future. We currently rely on LEH and its
affiliates (including Jonathan Carroll) to fund our working capital
requirements. There can be no assurance that LEH and its
affiliates (including Jonathan Carroll) will continue to fund our
working capital requirements.
Capital Spending
.
Capital improvements
primarily relate to construction of new petroleum storage tanks to
add to existing petroleum storage capacity. Due to the Final
Arbitration Award, capital spending in the Current Three Months was
minimal. During the Current Nine Months, we completed
several new tanks for which construction began during 2016.
Increasing petroleum storage capacity: (i) assists with
de-bottlenecking the facility, (ii) supports increased refinery
throughput up to approximately 17,000 bpd, and (iii) provides an
opportunity to generate additional tank rental revenue by leasing
to third-parties. When the Nixon Facility expansion
project is complete, total crude oil, condensate, and refined
petroleum products storage capacity at the plant will exceed
1,000,000 bbls.
Capital expenditures
at the Nixon Facility are being funded by Veritex through long-term
debt that we secured in 2015. Available funds under
these loans are reflected in restricted cash (current and
non-current portions) on our consolidated balance
sheets. Restricted cash (current portion) represents
funds to pay outstanding construction invoices and to fund
construction contingencies. Restricted cash (current
portion) totaled $1,500,380 and $3,347,835 at September 30, 2017
and December 31, 2016, respectively. Restricted cash,
non-current represents funds held in our disbursement account with
Veritex to complete construction of new petroleum storage tanks.
Restricted cash, noncurrent totaled $150,530 and $1,582,305 at
September 30, 2017 and December 31, 2016,
respectively.
Total capital
expenditures for the periods indicated were as
follows:
|
|
Three Months Ended September
30,
|
Nine Months Ended September
30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
financed by:
|
|
|
|
|
|
Cash
disbursements
|
$
369,518
|
$
4,182,747
|
$
1,777,219
|
$
11,255,725
|
|
Accounts
payable
(1)
|
169,283
|
8,330
|
1,650,910
|
2,601,709
|
|
|
$
538,801
|
$
4,191,077
|
$
3,428,129
|
$
13,857,434
|
(1)
Represents construction-related
vendor invoices awaiting payment from the loan disbursement
account.
See “Part I,
Item 1. Financial Statements – Note (10) Long-Term Debt,
Net” for additional disclosures related to borrowings for
capital spending.
Contractual
Obligations
.
Related Party
. See
“Part I, Item 1. Financial Statements – Note (8)
Related Party Transactions” in this Quarterly Report for a
summary of the agreements we have in place with related
parties.
GEL
. See “Part I, Item
1A. Risk Factors” in our Annual Report, as well as
“Part I, Item 1. Financial Statements – Note (1)
Organization
– Going Concern
– Final GEL Arbitration
Award"
in this Quarterly Report for disclosures
related to the contract-related dispute with GEL and the Final
Arbitration Award.
Supplemental Pipeline
Bonds
. See “Part I, Item 1. Financial
Statements – Note (18) Commitments and Contingencies –
Supplemental Pipeline Bonds” for a discussion of supplemental
pipeline bonding requirements.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Indebtedness
.
The principal
balances outstanding on our long-term debt, net (including related
party) for the periods indicated were as follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Term Loan Due
2034 (in default)
|
$
23,382,570
|
$
23,924,607
|
|
Second Term Loan Due
2034 (in default)
|
9,553,728
|
9,729,853
|
|
LEH Loan
Agreement
|
4,000,000
|
4,000,000
|
|
Notre Dame
Debt
|
4,977,953
|
1,300,000
|
|
March Ingleside
Note
|
1,168,748
|
722,278
|
|
March Carroll
Note
|
282,907
|
592,412
|
|
Capital
Leases
|
8,427
|
135,879
|
|
Term Loan Due
2017
|
-
|
184,994
|
|
|
43,374,333
|
40,590,023
|
|
|
|
|
|
Less: Current portion of long-term
debt, net
|
(39,756,045
)
|
(32,212,336
)
|
|
|
|
|
|
Less: Unamoritized debt issue
costs
|
(2,166,633
)
|
(2,262,997
)
|
|
|
|
|
|
|
$
1,451,655
|
$
6,114,690
|
Principal payments
on long-term debt totaled $265,063 in the Current Three Months
compared to $469,541 in the Prior Three Months. Payments
on long-term debt totaled $1,120,267 in the Current Nine Months
compared to $1,414,406 in the Prior Nine Months.
As described
elsewhere in this Quarterly Report, Veritex notified obligors that
the Final Arbitration Award constitutes an event of default under
the First Term Loan Due 2034 and Second Term Loan Due
2034. In addition to existing or potential events of
default related to the Final Arbitration Award, at September 30,
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 likely would require us to seek protection under
bankruptcy laws.
See “Part I,
Item 1. Financial Statements – Note (1) Organization –
Going Concern and Operating Risks, as well as Note (10) Long-Term
Debt, Net” for additional disclosures related to long-term
debt financial covenant violations and events of
default.
See
“Contractual Obligations – Related Party” within
the Liquidity and Capital Resources section for additional
disclosures with respect to related party
indebtedness.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Off-Balance Sheet
Arrangements
None.
Critical Accounting
Policies
Long-Lived Assets
.
Refinery and Facilities
. Management
expects to continue making improvements to the Nixon Facility based
on operation needs and technological advances. Additions
to refinery and facilities assets are capitalized. Expenditures for
repairs and maintenance are expensed as incurred and included as
operating expenses under the Amended and Restated Operating
Agreement.
We record refinery
and facilities at cost less any adjustments for depreciation or
impairment. Adjustment of the asset and the related accumulated
depreciation accounts are made for the refinery and facilities
asset’s retirement and disposal, with the resulting gain or
loss included in the consolidated statements of
operations. For financial reporting purposes,
depreciation of refinery and facilities assets is computed using
the straight-line method using an estimated useful life of 25 years
beginning when the refinery and facilities assets are placed in
service. We did not record any impairment of our
refinery and facilities assets for the years ended December 31,
2016 and 2015.
Pipelines and Facilities Assets
. Our
pipelines and facilities are recorded at cost less any adjustments
for depreciation or impairment. Depreciation is computed
using the straight-line method over estimated useful lives ranging
from 10 to 22 years. In accordance with Financial Accounting
Standards Board (“FASB”) Accounting Standards
Codification (“ASC”) guidance on accounting for the
impairment or disposal of long-lived assets, management performed
periodic impairment testing of our pipeline and facilities assets
in the fourth quarter of 2016. Upon completion of that testing, our
pipeline assets were fully impaired. All pipeline
transportation services to third-parties have ceased, existing
third-party wells along our pipeline corridor were 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
. Our oil and gas
properties are accounted for using the full-cost method of
accounting, whereby all costs associated with acquisition,
exploration and development of oil and gas properties, including
directly related internal costs, are capitalized on a cost center
basis. Amortization of such costs and estimated future
development costs are determined using the unit-of-production
method. All leases associated with our oil and gas
properties have expired, and our oil and gas properties were fully
impaired in 2011.
Construction in Progress
. Construction
in progress expenditures, which relate to construction and
refurbishment activities at the Nixon Facility, are capitalized as
incurred. Depreciation begins once the asset is placed in
service.
Revenue
Recognition
.
Refined Petroleum Products
Revenue
. Revenue from the sale of refined
petroleum products is recognized when sales prices are fixed or
determinable, collectability is reasonably assured, and title
passes. Title passage occurs when refined petroleum products are
delivered in accordance with the terms of the respective sales
agreements, and customers assume the risk of loss when title is
transferred. Transportation, shipping and handling costs
incurred are included in cost of refined products sold. Excise and
other taxes that are collected from customers and remitted to
governmental authorities are not included in revenue.
Tank Rental Revenue
. We
lease petroleum storage tanks to third-parties. Tank
rental fees are invoiced monthly in accordance with the terms of
the related lease agreement. Tank rental revenue is
recognized on a straight-line basis as earned.
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Asset Retirement
Obligations
.
FASB ASC guidance
related to AROs requires that a liability for the discounted fair
value of an ARO be recorded in the period in which it is incurred
and the corresponding cost capitalized by increasing the carrying
amount of the related long-lived asset. The liability is accreted
towards its future value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the
liability is settled for an amount other than the recorded amount,
a gain or loss is recognized.
Management has
concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facility assets arises and
a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
We recorded an ARO
liability related to future asset retirement costs associated with
dismantling, relocating or disposing of our offshore platform,
pipeline systems and related onshore facilities, as well as
plugging and abandoning wells and restoring land and sea beds. We
developed these cost estimates for each of our assets based upon
regulatory requirements, structural makeup, water depth, reservoir
characteristics, reservoir depth, equipment demand, current
retirement procedures, and construction and engineering
consultations. Because these costs typically extend many
years into the future, estimating future costs are difficult and
require management to make judgments that are subject to future
revisions based upon numerous factors, including changing
technology, political, and regulatory environments. We review our
assumptions and estimates of future abandonment costs on an annual
basis.
Income Taxes
.
We account for
income taxes under FASB ASC guidance related to income taxes, which
requires recognition of income taxes based on amounts payable with
respect to the current reporting period and the effects of deferred
taxes for the expected future tax consequences of events that have
been included in our financial statements or tax
returns. Under this method, deferred tax assets and
liabilities are determined based on the differences between the
financial accounting and tax basis of assets and liabilities, as
well as for operating losses and tax credit carryforwards using
enacted tax rates in effect for the year in which the differences
are expected to reverse.
As of each reporting
date, management considers new evidence, both positive and
negative, to determine the realizability of deferred tax
assets. Management considers whether it is more likely
than not that some portion or all the deferred tax assets will be
realized, which is dependent upon the generation of future taxable
income prior to the expiration of any NOL carryforwards. At
September 30, 2017 and December 31, 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 September 30, 2017
and December 31, 2016.
FASB ASC guidance
related to income taxes also prescribes a recognition threshold and
measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a
tax return, as well as guidance on de-recognition, classification,
interest and penalties, accounting in interim periods, disclosures,
and transition.
(See “Part I,
Item 1. Financial Statements - Note (15) Income Taxes” for
further information related to income taxes.)
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Recently Adopted Accounting
Guidance
The Financial
Accounting Standards Board (“FASB”) issues an
Accounting Standards Update (“ASU”) to communicate
changes to the FASB Accounting Standards Codification, including
changes to non-authoritative SEC content. Recently
adopted ASUs include:
ASU 2016-18, Statement of Cash Flows
(Topic 230: Restricted Cash (A Consensus of the FASB Emerging
Issues Task Force
. In November 2016, FASB issued ASU
2016-18, which requires that a statement of cash flows explain the
change during the period in the total of cash, cash equivalents,
and amounts generally described as restricted cash or restricted
cash equivalents. We adopted this accounting pronouncement
effective December 31, 2016. Accordingly, our consolidated
statement of cash flows for the nine months ended September 30,
2016 was changed to combine restricted cash with cash and cash
equivalents.
ASU 2015-11,
Inventory (Topic 330):
Simplifying the Measurement of
Inventory
. In July 2015, FASB issued ASU 2015-11, which
requires an entity to measure inventory at the lower of cost or net
realizable value. We adopted this accounting
pronouncement effective January 1, 2017. The adoption of
ASU 2015-11 did not have a significant impact on our consolidated
financial statements.
Remainder of Page
Intentionally Left Blank
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
ITEM 4. CONTROLS AND
PROCEDURES
Evaluation of Disclosure Controls and
Procedures
Under the
supervision of, and with the participation of our management,
including our Chief Executive Officer (principal executive officer)
and Chief Financial Officer (principal financial officer), we
conducted an evaluation of the effectiveness of our disclosure
controls and procedures, as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934, as amended
(the “Exchange Act”), as of the end of the period
covered by this Quarterly Report. Based on our evaluation, our
Chief Executive Officer (principal executive officer) and Chief
Financial Officer (principal financial officer) concluded that our
disclosure controls and procedures were effective as of the end of
the period covered by this report to ensure that information
required to be disclosed by us in reports that we file or submit
under the Exchange Act, are recorded, processed, summarized and
reported within the time periods specified in the SEC’s rules
and forms.
Changes in Internal Control over
Financial Reporting
Management concluded
that our internal control over financial reporting was effective as
of December 31, 2016. There has been no change in our internal
control over financial reporting (as defined in Rule 13a-15(f) and
15d-15(f) under the Exchange Act) that occurred during the three
and nine months ended September 30, 2017 that has materially
affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
Remainder of Page
Intentionally Left Blank
|
BLUE DOLPHIN ENERGY
COMPANY
|
|
FORM 10-Q
3/31/17
|