Consolidated
Statements of Operations (Unaudited)
|
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
(in thousands, except share and per-share amounts)
|
|
REVENUE
FROM OPERATIONS
|
|
|
|
|
|
Refinery
operations
|
$77,537
|
$94,468
|
$222,652
|
$254,245
|
|
Tolling
and terminaling
|
1,096
|
1,075
|
3,253
|
2,659
|
|
Total
revenue from operations
|
78,633
|
95,543
|
225,905
|
256,904
|
|
|
|
|
|
|
|
COST
OF GOODS SOLD
|
|
|
|
|
|
Crude
oil, fuel use, and chemicals
|
74,163
|
92,167
|
213,714
|
243,245
|
|
Other
conversion costs
|
2,066
|
1,959
|
6,587
|
6,463
|
|
Total
cost of goods sold
|
76,229
|
94,126
|
220,301
|
249,708
|
|
|
|
|
|
|
|
Gross
profit
|
2,404
|
1,417
|
5,604
|
7,196
|
|
|
|
|
|
|
|
COST
OF OPERATIONS
|
|
|
|
|
|
LEH
operating fee
|
144
|
154
|
477
|
462
|
|
Other
operating expenses
|
52
|
33
|
165
|
133
|
|
General
and administrative expenses
|
655
|
929
|
1,904
|
2,277
|
|
Depletion,
depreciation and amortization
|
632
|
478
|
1,855
|
1,396
|
|
Accretion
of asset retirement obligations
|
-
|
61
|
-
|
205
|
|
|
|
|
|
|
|
Total
cost of operations
|
1,483
|
1,655
|
4,401
|
4,473
|
|
|
|
|
|
|
|
Income
(loss) from operations
|
921
|
(238)
|
1,203
|
2,723
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
Easement,
interest and other income
|
1
|
18
|
2
|
20
|
|
Interest
and other expense
|
(1,883)
|
(760)
|
(4,718)
|
(2,255)
|
|
Gain
on extinguishment of debt
|
9,128
|
-
|
9,128
|
-
|
|
Total
other income (expense)
|
7,246
|
(742)
|
4,412
|
(2,235)
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
8,167
|
(980)
|
5,615
|
488
|
|
|
|
|
|
|
|
Income
tax benefit
|
-
|
43
|
-
|
260
|
|
|
|
|
|
|
|
Net
income (loss)
|
$8,167
|
$(937)
|
$5,615
|
$748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) per common share:
|
|
|
|
|
|
Basic
|
$0.74
|
$(0.09)
|
$0.51
|
$0.07
|
|
Diluted
|
$0.74
|
$(0.09)
|
$0.51
|
$0.07
|
|
|
|
|
|
|
Weighted average number of common shares outstanding:
|
|
Basic
|
10,975,514
|
10,925,513
|
10,975,514
|
10,925,513
|
|
Diluted
|
10,975,514
|
10,925,513
|
10,975,514
|
10,925,513
|
See
accompanying notes to consolidated financial
statements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Consolidated
Statements of Cash Flows (Unaudited)
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
Net
income
|
$5,615
|
$748
|
|
Adjustments
to reconcile net income to net cash
|
|
|
|
provided by (used
in) operating activities:
|
|
|
|
Depletion,
depreciation and amortization
|
1,855
|
1,396
|
|
Deferred income
tax
|
-
|
(216)
|
|
Amortization of
debt issue costs
|
409
|
96
|
|
Guaranty fees paid
in kind
|
471
|
-
|
|
Accretion of asset
retirement obligations
|
-
|
205
|
|
Gain on
extinguishment of debt
|
(9,128)
|
-
|
|
Changes in
operating assets and liabilities
|
|
|
|
Accounts
receivable
|
43
|
(312)
|
|
Accounts
receivable, related party
|
(321)
|
653
|
|
Prepaid expenses
and other current assets
|
522
|
760
|
|
Deposits and other
assets
|
32
|
(65)
|
|
Inventory
|
(224)
|
462
|
|
Accrued arbitration
award
|
(12,000)
|
(4,000)
|
|
Accounts payable,
accrued expenses and other liabilities
|
1,689
|
1,023
|
|
Accounts payable,
related party
|
513
|
404
|
|
Net cash provided
by (used in) operating activities
|
(10,524)
|
1,154
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
Capital
expenditures
|
(1,458)
|
(1,826)
|
|
Net cash used in
investing activities
|
(1,458)
|
(1,826)
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
Proceeds from line
of credit
|
12,402
|
-
|
|
Payments on
debt
|
(990)
|
(723)
|
|
Payments of debt
issuance costs
|
(322)
|
-
|
Net activity on
related-party debt
|
(407)
|
924
|
|
Net cash provided
by financing activities
|
11,497
|
201
|
|
Net change in cash,
cash equivalents, and restricted cash
|
(485)
|
(471)
|
|
|
|
|
|
CASH, CASH
EQUIVALENTS, AND RESTRICTED CASH AT BEGINNING OF
PERIOD
|
1,665
|
2,146
|
|
CASH, CASH
EQUIVALENTS, AND RESTRICTED CASH AT END OF PERIOD
|
$1,180
|
$1,675
|
|
|
|
|
|
Supplemental
Information:
|
|
|
|
Non-cash investing
and financing activities:
|
|
|
|
Financing of
capital expenditures via accounts payable and finance
leases
|
$86
|
$82
|
|
Line of credit
closing costs included in principal balance
|
$398
|
$-
|
|
Interest
paid
|
$2,261
|
$2,173
|
|
Income taxes
paid
|
$-
|
$-
|
See
accompanying notes to consolidated financial
statements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements
|
Nature of Operations. Blue Dolphin Energy Company is a
publicly traded Delaware corporation primarily engaged in the
refining and marketing of petroleum products. We also provide
tolling and storage terminaling services. Our assets, which are in
Nixon, Texas, primarily include a 15,000-bpd crude distillation
tower and more than 1.0 million bbls of petroleum storage tanks
(collectively the “Nixon Facility”). Pipeline
transportation and oil and gas operations are no longer
active.
Structure and Management. Blue Dolphin is controlled by
Lazarus Energy Holdings, LLC (“LEH”). LEH operates and
manages all Blue Dolphin properties pursuant to an Amended and
Restated Operating Agreement (the “Amended and Restated
Operating Agreement”). Jonathan Carroll is Chairman of the
Board of Directors (the “Board”), Chief Executive
Officer, and President of Blue Dolphin, as well as a majority owner
of LEH. Together, LEH and Jonathan Carroll owned 79.8% of our
common stock, par value $0.01 per share (the “Common
Stock”) at September 30, 2019. (See “Note (9)
Related-Party Transactions,” “Note (11) Long-Term Debt
and Accrued Interest” and “Note (18) Commitments and
Contingencies – Financing Agreements” for additional
disclosures related to LEH, the Amended and Restated Operating
Agreement, and Jonathan Carroll.)
We have
the following active subsidiaries:
●
Blue Dolphin Pipe
Line Company, a Delaware corporation
(“BDPL”);
●
Blue Dolphin
Petroleum Company, a Delaware corporation;
●
Blue Dolphin
Services Co., a Texas corporation
(“BDSC”);
●
Lazarus Energy,
LLC, a Delaware limited liability company
(“LE”);
●
Lazarus Refining
& Marketing, LLC, a Delaware limited liability company
(“LRM”); and
●
Nixon Product
Storage, LLC, a Delaware limited liability company
(“NPS”).
See
“Part I, Item 1. Business” and “Part I, Item 2.
Properties” in our Annual Report for additional information
regarding our operating subsidiaries, principal facilities, and
assets.
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:
Defaults Under Veritex Secured Loan Agreements. LE and LRM each have loans with Veritex
Community Bank (“Veritex”), as successor in interest to
Sovereign Bank (“Sovereign”) by merger, in the original
aggregate amount of $35.0 million. These Veritex loans are
guaranteed 100% by the U.S. Department of Agriculture
(“USDA”).
●
Events of
Default. Veritex delivered to
obligors notices of default under secured loan agreements with
Veritex, stating that the Final Arbitration Award constituted an
event of default under the secured loan agreements. The occurrence
of an event of default permitted 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 did not
accelerate or call due the secured loan agreements considering the
Settlement Agreement. Instead, 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.
●
Financial Covenant
Defaults. In addition to
existing events of default related to the Final Arbitration Award,
at September 30, 2019, 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.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
The debt associated with these loans was classified within the
current portion of long-term debt on our consolidated balance
sheets at September 30, 2019 and December 31, 2018 due to existing
events of default related to the Final Arbitration Award as well as
the uncertainty of LE and LRM’s ability to meet financial
covenants in the secured loan agreements in the
future.
Veritex worked with LE and LRM and was aware and party to all
discussions and arrangements with GEL surrounding the
Settlement Agreement, all amendments, and the final and effective
Settlement with GEL. In a notice to obligors dated April 30, 2019
(the "Veritex Consent'), Veritex agreed to waive certain covenant
defaults and forbear from enforcing its remedies under the secured
loan agreements subject to: (i) the agreement and concurrence of
the USDA and (ii) the replenishment of a payment reserve account in
the amount of $1.0 million as required by one of the secured loan
agreements on or before August 31, 2019. As of the
filing date of this Quarterly Report, the payment reserve account
had not been fully replenished. Any exercise by Veritex of its
rights and remedies under such secured loan agreements would have a
material adverse effect on our business operations,
including crude oil and condensate procurement and our customer
relationships; financial condition; and results of operations. In
such a case, the trading price of our common stock and the value of
an investment in our common stock could significantly decrease,
which could lead to holders of our common stock losing their
investment in our common stock in its entirety.
Net Losses and Working Capital Deficits. For the three months ended September 30, 2019,
we reported net income of $8.2 million, or $0.74 per share.
Excluding the $9.1 million gain on extinguishment of debt, we would
have reported a net loss of $1.0 million, or a loss of $0.09 per
share, for the three months ended September 30, 2019.
Comparatively, we reported a net loss of $0.9 million, or a loss of
$0.09 per share, for the three months ended September 30,
2018.
For the nine months ended September 30, 2019, we reported net
income of $5.6 million, or $0.51 per share. Excluding the $9.1
million gain on extinguishment of debt, we would have reported a
net loss of $3.5 million, or $0.32 per share, for the nine months
ended September 30, 2019. This compares to reported net income of
$0.7 million, or income of $0.07 per share, for the nine months
ended September 30, 2018.
We had a working capital deficit of $64.9 million and $71.9 million
at September 30, 2019 and December 31, 2018, respectively.
Excluding the current portion of long-term debt, we had a working
capital deficit of $22.9 million and $30.0 at September 30, 2019 at
December 31, 2018, respectively.
For additional disclosures related to defaults under secured loan
agreements and other long-term debt, see “Item 1. Financial
Statements – Note (11) Long-Term Debt and Accrued
Interest” and “ – Note (9) Related Party
Transactions” in this Quarterly Report. For additional
disclosures related to the Settlement Agreement, refer to
“Item 1. Financial Statements – Note (18) Commitments
and Contingencies – Legal Matters” and “Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Final Arbitration Award and
Settlement Agreement” in the Quarterly Report, as well as
“Part I, Item 3. Legal Proceedings” in our Annual
Report on Form 10-K for the period ended December 31, 2018 (the
“Annual Report”).
Operating Risks. Successful
execution of our business strategy depends on several key factors,
including, having adequate working capital to meet operational
needs and regulatory requirements, maintaining safe and reliable
operations at the Nixon Facility, meeting contractual obligations,
and having favorable margins on refined petroleum products. During
the three months ended September 30, 2019, management successfully
finalized the Settlement with GEL and realized a $9.1 million gain
on the extinguishment of the liability, and management believes
that it is continuing to take other steps to further improve our
operations and financial stability. However, there can be no assurance that our
business strategy will be successful, that LEH and its affiliates
will continue to fund our working capital needs, or that we will be
able to obtain additional financing or meet financial assurance
(bonding) requirements on commercially reasonable terms or at all.
If Veritex exercises its rights and remedies under the secured loan
agreements, our business,
financial condition, and results of operations will be materially
adversely affected.
For
additional disclosures related to our business strategy and risk
factors that could materially affect our future business, financial
condition and results of operations, refer to “Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations Results of Operations” and
“Liquidity and Capital Resources” in this Quarterly
Report, as well as “Part I, Item 1. Business – Business
Strategy,” “Part I, Item 1A. Risk Factors,” and
“Part I, Item 3. Legal Proceedings” in our Annual
Report.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
|
(2)
|
Basis of Presentation
|
The
accompanying unaudited consolidated financial statements, which
include Blue Dolphin and its subsidiaries, have been prepared in
accordance with GAAP for interim consolidated financial information
pursuant to the rules and regulations of the SEC under Article 10
of Regulation S-X and the instructions to Form 10-Q. 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, 2018 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, 2019 are not necessarily indicative
of the results that may be expected for the fiscal year ending
December 31, 2019, 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.
Restricted Cash. Restricted cash, current portion
primarily represents a payment reserve account held by Veritex as
security for payments under a loan agreement. Restricted cash,
noncurrent represents funds held in the Veritex disbursement
account for payment of construction related expenses to complete
building new petroleum storage tanks.
Accounts Receivable and Allowance for Doubtful Accounts.
Accounts receivable are presented net of any necessary allowance(s)
for doubtful accounts. Receivables are recorded at the invoiced
amount and generally do not bear interest. An allowance for
doubtful accounts is established, when necessary, based
on prior experience and other factors which, in management's
judgment, deserve consideration in estimating bad debts.
Management assesses collectability primarily based on
the current aging status of the customer's account, our
historical collection experience with the customer, and the
customer's financial condition. Based on a review of
these factors, management establishes or adjusts the allowance for
specific customers and the accounts receivable portfolio as a
whole. We had an allowance for doubtful accounts of $0.1
million at both September 30, 2019 and December 31,
2018.
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 goods sold. (See “Note (7)
Inventory” for additional disclosures related to our
inventory.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Property and Equipment.
Refinery and Facilities. Management expects to continue
making improvements to the crude distillation tower based on
operational needs and technological advances. Additions to refinery
and facilities assets are capitalized. Expenditures for repairs and
maintenance are expensed as incurred.
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 periods 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”) 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 have been permanently abandoned, and no
new third-party wells are being drilled near our
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, including capitalized interest, relate to
construction and refurbishment activities at the Nixon Facility.
These expenditures are capitalized as incurred. Depreciation begins
once the asset is placed in service.
(See
“Note (8) 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.)
Revenue Recognition. We adopted the provisions of FASB ASU
(defined below) 2014-09, Revenue
from Contracts with Customers (ASC 606), on January 1,
2018, as described below in “New Pronouncements
Adopted.” Accordingly, our revenue recognition accounting
policy has been revised to reflect the adoption of this
standard.
Refinery Operations Revenue. Revenue from the sale of
refined petroleum products is recognized when the product is sold
to the customer in fulfillment of performance obligations. Each
load of refined petroleum product is separately identifiable and
represents a distinct performance obligation to which the
transaction price is allocated. Performance obligations are met
when control is transferred to the customer. Control is transferred
to the customer when the product has been lifted or, in cases where
the product is not lifted immediately (bill and hold arrangements),
when the product is added to the customer’s bulk inventory as
stored at the Nixon Facility.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
We
consider a variety of facts and circumstances in assessing the
point of control transfer, including but not limited to: whether
the purchaser can direct the use of the refined petroleum product,
the transfer of significant risks and rewards, our rights to
payment, and transfer of legal title. In each case, the term
between the sale and when payment is due is not significant.
Transportation, shipping, and handling costs incurred are included
in cost of goods sold. Excise and other taxes that are collected
from customers and remitted to governmental authorities are not
included in revenue.
Tolling and Terminaling Revenue. Tolling and terminaling
represents fees pursuant to: (i) tolling agreements, whereby a
customer agrees to pay a certain fee per gallon or barrel for
throughput volumes moving through the naphtha stabilizer unit and a
fixed monthly reservation fee for use of the naphtha stabilizer
unit and (ii) tank storage agreements, whereby a customer agrees to
pay a certain fee per tank based on tank size over a period of time
for the storage of products.
We
typically satisfy performance obligations for tolling and
terminaling operations with the passage of time. We determine the
transaction price at agreement inception based on the guaranteed
minimum amount of revenue over the term of the agreement. We
allocate the transaction price to the single performance obligation
that exists under the agreement, and we recognize revenue in the
amount for which we have a right to invoice. Generally,
payment terms do not exceed 30 days.
Revenue
from tank storage customers may, from time to time, include fees
for ancillary services, such as in-tank and tank-to-tank blending.
These services are considered optional to the customer, and the
price we charge for such services is not included in the fixed cost
under the customer’s tank storage agreement. Ancillary
services are considered a separate performance obligation by us
under the tank storage agreement. The performance obligation is
satisfied when the requested service has been performed in the
applicable period.
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 of the deferred tax assets will be realized,
which is dependent upon the generation of future taxable income
prior to the expiration of any net operating loss
(“NOL”) carryforwards. When management determines that
it is more likely than not that a tax benefit will not be realized,
a valuation allowance is recorded to reduce deferred tax assets. A
significant piece of objective negative evidence evaluated was
cumulative losses incurred over the three-year period ended
December 31, 2018. Such objective evidence limits the ability to
consider other subjective evidence, such as projections for future
growth. Based on this evaluation, we recorded a valuation allowance
against the deferred tax assets for which realization was not
deemed more likely than not as of September 30, 2019 and December
31, 2018. We expect to recover deferred tax assets related to the
Alternative Minimum Tax (“AMT”) credit carryforwards.
In addition, we have NOL carryforwards that remain available for
future use.
The
benefit of an uncertain tax position is recognized in the financial
statements if it meets a minimum recognition threshold. A
determination is first made as to whether it is more likely than
not that the income tax position will be sustained, based upon
technical merits, upon examination by the taxing authorities. If
the income tax position is expected to meet the
more-likely-than-not criteria, the benefit recorded in the
financial statements equals the largest amount that is greater than
50% likely to be realized upon its ultimate settlement. At
September 30, 2019 and December 31, 2018, there were no uncertain
tax positions for which a reserve or liability was necessary. (See
“Note (16) Income Taxes” for further information
related to income taxes.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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. As a result of the Final
Arbitration Award, which represents a significant adverse change
that could affect the value of a long-lived asset, management
performed potential impairment testing of our refinery and
facilities assets in the fourth quarter of 2018. Upon completion of
that testing, we determined that no impairment was necessary at
December 31, 2018. We did not record any impairment of our refinery
and facilities assets for the periods presented.
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 incurred, and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted towards its future
value each period, and the capitalized cost is depreciated over the
useful life of the related asset. If the liability is settled for
an amount other than the recorded amount, a gain or loss is
recognized.
Management
has concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facilities assets arises
and a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
We
recorded an ARO liability related to future asset retirement costs
associated with dismantling, relocating, or disposing of our
offshore platform, pipeline systems, and related onshore
facilities, as well as for plugging and abandoning wells and
restoring land and sea beds. The cost estimates for each of our
assets were developed based upon regulatory requirements,
structural makeup, water depth, reservoir characteristics,
reservoir depth, equipment demand, current retirement procedures,
and construction and engineering consultations. 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 (13) Asset
Retirement Obligations” for additional information related to
our AROs.)
Computation of Earnings Per Share. We apply the provisions
of FASB ASC guidance for computing earnings per share
(“EPS”). The guidance requires the presentation of
basic EPS, which excludes dilution and is computed by dividing net
income available to common stockholders by the weighted-average
number of shares of common stock outstanding for the period. The
guidance requires dual presentation of basic EPS and diluted EPS on
the face of our consolidated statements of operations and requires
a reconciliation of the denominator of basic EPS and diluted EPS.
Diluted EPS is computed by dividing net income available to common
stockholders by the diluted weighted average number of common
shares outstanding, which includes the potential dilution that
could occur if securities or other contracts to issue shares of
common stock were converted to common stock that then shared in the
earnings of the entity.
The
number of shares related to options, warrants, restricted stock,
and similar instruments included in diluted EPS is based on the
“Treasury Stock Method” prescribed in FASB ASC guidance
for computation of EPS. This method assumes theoretical repurchase
of shares using proceeds of the respective stock option or warrant
exercised, and, for restricted stock, the amount of compensation
cost attributed to future services that has not yet been recognized
and the amount of any current and deferred tax benefit that would
be credited to additional paid-in-capital upon the vesting of the
restricted stock, at a price equal to the issuer’s average
stock price during the related earnings period. Accordingly, the
number of shares includable in the calculation of EPS in respect of
the stock options, warrants, restricted stock, and similar
instruments is dependent on this average stock price and will
increase as the average stock price increases. (See “Note
(17) Earnings Per Share” for additional information related
to EPS.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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:
ASUs 2019-01, 2018-20, 2018-11, 2018-10, and 2016-02,
Leases (Topic 842). In
February 2016, FASB amended its accounting guidance for leases.
Subsequently, FASB issued several clarifications and updates. The
guidance requires a lessee to recognize assets and liabilities on
the balance sheet arising from leases with terms greater than 12
months. While lessor guidance is relatively unchanged, certain
amendments were made to confirm with changes made to lessee
accounting and the amended revenue recognition guidance. The new
guidance continues to classify leases as either finance or
operating, with classification affecting the presentation and
pattern of expense and income recognition, in the statement of
operations. It also requires additional quantitative and
qualitative disclosures about leasing arrangements. We adopted the
new guidance on January 1, 2019 using the modified retrospective
approach, which was applied beginning on the adoption date.
Comparative information has not been restated and continues to be
reported under the accounting guidance in effect for those periods.
The adoption did not have a material effect on our consolidated
statements of operations or cash flows. On the adoption date we
recognized operating lease right-of-use assets, net of pre-existing
deferred rent, and operating lease liabilities on our consolidated
balance sheet of approximately $0.8 million and $0.9 million,
respectively.
ASU 2018-09, Codification Improvements. In July 2018, FASB
issued ASU 2018-09. This guidance affects a wide variety of topics
in the codification and represents changes to clarify, correct
errors in, or make minor improvements to the codification. The
amendments make the codification easier to understand and easier to
apply by eliminating inconsistencies and providing clarifications.
The amendments apply to all reporting entities within the scope of
the affected accounting guidance. Some of the amendments in ASU
2018-09 do not require transition guidance and will be effective
upon issuance. However, many of the amendments do have transition
guidance with effective dates for annual periods beginning after
December 15, 2018, for public business entities. Adoption of this
guidance did not have a significant impact on our consolidated
financial statements.
ASU 2014-09, Revenue from Contracts with Customers (ASC
606). We adopted this accounting pronouncement effective
January 1, 2018, using a modified retrospective approach, which
required us to apply the new revenue standard to: (i) all new
revenue contracts entered into after January 1, 2018 and (ii) all
existing revenue contracts as of January 1, 2018. In accordance
with this approach, our consolidated revenues for the periods prior
to January 1, 2018 were not revised. In November 2018, FASB issued
ASU 2018-18, Collaborative
Arrangements (Topic 808). ASU 2018-18 clarifies the
interaction between ASC 808 and ASC 606. Our implementation
activities related to ASC 606 are complete, and we did not have any
material differences in the amount or timing of revenues as a
result of the adoption of ASC 606. Our largest revenue streams
consist of orders received from our customers for crude-oil derived
specialty products based on market prices. These revenues are
recognized at a point in time upon transfer of control of the
product in accordance with contractual terms. With respect to ASC
808, we are not party to a collaborative agreement with a third
party.
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 2019-07, Codification
Updates to SEC Sections. In July 2019, FASB issued ASU
2019-07. This ASU amends certain SEC sections or paragraphs within
the FASB ASC. The amendments are being made pursuant to SEC Final
Rule Releases No. 33-10532, Disclosure Update and Simplification,
and Nos. 33-10231 and 33-10442, Investment Company Reporting
Modernization, and Miscellaneous Updates (SEC Update). The SEC
Final Rule Releases, which also require improvements to the
eXtensible
Business Reporting Language (“XBRL”) taxonomy,
were made to improve, update, and simplify SEC regulations on
financial reporting and disclosure. For public companies, the
amendments in ASU 2019-07 are effective upon issuance. We do not
expect adoption of this guidance to have a significant impact on
our consolidated financial statements.
ASU 2018-17, Consolidation (Topic 810). In October 2018,
FASB issued ASU 2018-17. This ASU provides targeted improvements to
related-party guidance for variable interest entities. In
particular, indirect interests held through related parties in
common control arrangements should be considered on a proportional
basis for determining whether fees paid to decision makers and
service providers are variable interests. For entities other than
private companies, the amendments in ASU 2018-17 are effective for
fiscal years beginning after December 15, 2019, and interim periods
within those fiscal years. We do not expect adoption of this
guidance to have a significant impact on our consolidated financial
statements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
ASU 2018-05, Income Taxes (Topic 740). In March
2018, FASB issued ASU 2018-05. This guidance amends SEC paragraphs
in ASC 740, Income Taxes, to reflect Staff Accounting Bulletin No.
118, which provides guidance for companies that are not able to
complete their accounting for the income tax effects of the Tax
Cuts and Jobs Act in the period of enactment. This
guidance also includes amendments to the XBRL
Taxonomy. For public business entities, the amendments
in ASU 2018-05 are effective for fiscal years ending after December
15, 2020. Early adoption is permitted. We do not expect
adoption of this guidance to have a significant impact 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.
|
(4)
|
Revenue
and Segment Information
|
We have
two reportable business segments: (i) Refinery Operations and (ii)
Tolling and Terminaling. Refinery operations relate to the refining
and marketing of petroleum products at our 15,000-bpd crude
distillation tower. Tolling and terminaling operations relate to
tolling and storage terminaling services under related-party and
third-party lease agreements. Both operations are conducted at the
Nixon Facility.
Revenue from Contracts with Customers.
Disaggregation of Revenue. Revenue is presented in the table
below under “Segment Information” disaggregated by
business segment because this is the level of disaggregation that
management has determined to be beneficial to users of our
financial statements.
Receivables from Contracts with Customers. Our receivables
from contracts with customers are presented as receivables, net on
our consolidated balance sheets.
Remaining Performance Obligations. Most of our contracts
with customers are spot contracts and therefore have no remaining
performance obligations.
Segment Information. Business segment information for the
periods indicated (and as of the dates indicated) was as
follows:
|
|
Three Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues (excluding
intercompany fees and sales)
|
$77,537
|
$1,096
|
$-
|
$78,633
|
$94,468
|
$1,075
|
$-
|
$95,543
|
|
Intercompany fees and
sales
|
(668)
|
668
|
-
|
-
|
(873)
|
873
|
-
|
-
|
|
Operation costs and
expenses(1)
|
(76,088)
|
(285)
|
(52)
|
(76,425)
|
(93,656)
|
(624)
|
(94)
|
(94,374)
|
|
Segment contribution
margin
|
$781
|
$1,479
|
$(52)
|
$2,208
|
$(61)
|
$1,324
|
$(94)
|
$1,169
|
|
General and administrative
expenses
|
(292)
|
(68)
|
(295)
|
(655)
|
(375)
|
(65)
|
(489)
|
(929)
|
|
Depreciation and
amortization
|
(481)
|
(99)
|
(52)
|
(632)
|
(432)
|
(46)
|
-
|
(478)
|
|
Interest and other non-operating
income (expenses), net
|
|
|
|
7,246
|
|
|
|
(742)
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes
|
|
|
|
8,167
|
|
|
|
(980)
|
|
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
|
-
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
|
|
|
$8,167
|
|
|
|
$(937)
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
$964
|
$-
|
$-
|
$964
|
$372
|
$223
|
$-
|
$595
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
assets
|
$49,613
|
$18,994
|
$1,933
|
$70,540
|
$51,816
|
$19,425
|
$926
|
$72,167
|
|
(1)
|
Operation
costs within Refinery Operations includes the arbitration award and
associated fees. Operation cost within Tolling and Terminaling
includes terminal operating expenses, an allocation of other costs
(e.g. insurance and maintenance), and associated refinery fuel use
costs. Operation cost within Corporate and Other includes expenses
associated with our pipeline assets and oil and gas leasehold
interests (such as accretion).
|
|
|
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net revenues (excluding
intercompany fees and sales)
|
$222,652
|
$3,253
|
$-
|
$225,905
|
$254,245
|
$2,659
|
$-
|
$256,904
|
|
Intercompany fees and
sales
|
(1,927)
|
1,927
|
-
|
-
|
(2,419)
|
2,419
|
-
|
-
|
|
Operation costs and
expenses(1)
|
(219,766)
|
(1,012)
|
(165)
|
(220,943)
|
(248,078)
|
(2,092)
|
(338)
|
(250,508)
|
|
Segment contribution
margin
|
$959
|
$4,168
|
$(165)
|
$4,962
|
$3,748
|
$2,986
|
$(338)
|
$6,396
|
|
General and administrative
expenses
|
(898)
|
(173)
|
(833)
|
(1,904)
|
(929)
|
(156)
|
(1,192)
|
(2,277)
|
|
Depreciation and
amortization
|
(1,429)
|
(297)
|
(129)
|
(1,855)
|
(1,258)
|
(138)
|
-
|
(1,396)
|
|
Interest and other non-operating
income (expenses), net
|
|
|
|
4,412
|
|
|
|
(2,235)
|
|
|
|
|
|
|
|
|
|
|
|
Income before income
taxes
|
|
|
|
5,615
|
|
|
|
488
|
|
|
|
|
|
|
|
|
|
|
|
Income tax
benefit
|
|
|
|
-
|
|
|
|
260
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
$5,615
|
|
|
|
$748
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
$1,375
|
$83
|
$-
|
$1,458
|
$1,141
|
$767
|
$-
|
$1,908
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable
assets
|
$49,613
|
$18,994
|
$1,933
|
$70,540
|
$51,816
|
$19,425
|
$926
|
$72,167
|
|
(1)
|
Operation
costs within Refinery Operations includes the arbitration award and
associated fees. Operation cost within Tolling and Terminaling
includes terminal operating expenses, an allocation of other costs
(e.g. insurance and maintenance), and associated refinery fuel use
costs. Operation cost within Corporate and Other includes expenses
associated with our pipeline assets and oil and gas leasehold
interests (such as accretion).
|
|
(6)
|
Prepaid Expenses and Other Current Assets
|
Prepaid
expenses and other current assets as of the dates indicated
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
insurance
|
$537
|
$437
|
|
Prepaid
crude oil and condensate
|
525
|
1,166
|
|
Prepaid
easement renewal fees
|
127
|
143
|
|
Other
prepaids
|
75
|
40
|
|
|
|
|
|
|
$1,264
|
$1,786
|
Inventory
as of the dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
oil and condensate
|
$1,177
|
$861
|
|
AGO
|
285
|
276
|
|
Chemicals
|
142
|
106
|
|
Naphtha
|
99
|
143
|
|
Propane
|
25
|
17
|
|
LPG
mix
|
6
|
5
|
|
HOBM
|
-
|
102
|
|
|
|
|
|
|
$1,734
|
$1,510
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
|
(8)
|
Property, Plant and Equipment, Net
|
Property,
plant and equipment, net, as of the dates indicated consisted of
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
and facilities
|
$66,308
|
$63,058
|
|
Land
|
566
|
566
|
|
Other
property and equipment
|
833
|
747
|
|
|
67,707
|
64,371
|
|
|
|
|
|
Less:
Accumulated depletion, depreciation, and amortization
|
(12,156)
|
(10,429)
|
|
|
55,551
|
53,942
|
|
|
|
|
|
Construction
in progress
|
8,861
|
10,755
|
|
|
|
|
|
|
$64,412
|
$64,697
|
We
capitalize interest cost incurred on funds used to construct
property, plant, and equipment. Capitalized interest, which is
recorded as part of the asset to which it relates, is depreciated
over the asset’s useful life. Interest cost capitalized,
which is currently included in construction in progress, was $0.7
million and $1.3 million at September 30, 2019 and December 31,
2018, respectively. Capital expenditures at the Nixon Facility are
being funded by working capital derived from revenue from
operations and LEH and its affiliates (including Jonathan Carroll),
as well as from long-term debt from Veritex that was secured in
2015 for expansion of the Nixon Facility. Unused amounts under the
Veritex loans are reflected in restricted cash (current and
non-current portions) on our consolidated balance sheets.
See “Note (11) Long-Term Debt
and Accrued Interest” for additional disclosures related to
borrowings for capital spending.
|
(9)
|
Related-Party Transactions
|
Related Parties. Blue Dolphin and certain of its
subsidiaries are party to several agreements with LEH and its
affiliates. Management believes that these related-party
transactions were consummated on terms equivalent to those that
prevail in arm's-length transactions. Related-party transactions
consist of the following 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 owned 79.8% of our Common Stock at September 30,
2019. Related-party agreements with LEH include: (i) an Amended and
Restated Operating Agreement with Blue Dolphin and LE, (ii) a Jet
Fuel Sales Agreement with LE, (iii) a Loan Agreement with BDPL,
(iv) an Amended and Restated Promissory Note with Blue Dolphin, and
(v) an office sublease-agreement with BDSC.
Ingleside Crude, LLC (“Ingleside”). Ingleside is
a related party of LEH and Jonathan Carroll. Blue Dolphin is party
to an Amended and Restated Promissory Note with
Ingleside.
Lazarus Texas Refinery I, LLC (“LTRI”). LTRI is a related party
of LEH and Jonathan Carroll. During the quarter ended September 30,
2019, LE purchased refurbished refinery equipment from LTRI for use
at the Nixon Facility.
Lazarus Marine Terminal I, LLC (“LMT”). LMT is a
related party of LEH and Jonathan Carroll. LE was party to a Dock
Tolling Agreement with LMT that was terminated during the quarter
ended September 30, 2019.
Jonathan Carroll. Jonathan Carroll is Chairman of the Board,
Chief Executive Officer, and President of Blue Dolphin.
Related-party agreements with Jonathan Carroll include: (i) Amended
and Restated Guaranty Fee Agreements with LE and LRM and (ii) an
Amended and Restated Promissory Note with Blue Dolphin. The
guaranty fee agreements and the promissory note relate to LE and
LRM USDA-guaranteed loans.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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.
Operations Related Agreements.
Amended and Restated Operating Agreement. LEH operates and
manages all Blue Dolphin properties pursuant to the Amended and
Restated Operating Agreement. The Amended and Restated Operating
Agreement, which was restructured in 2017 following cessation of
crude supply and marketing activities under the Crude Supply
Agreement and Joint Marketing Agreement with GEL, expires: (i) on
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. The Board plans to review
the Amended and Restated Operating Agreement during the first
quarter of 2020 to evaluate renewal.
LEH
receives a management fee calculated as 5% of certain of our direct
operating expenses. During the fourth quarter of 2018, the
management fee was changed to be calculated based on year to date
operating expenses incurred, regardless of whether they were paid
for by LEH or LE. The management fee was previously reflected
within refinery operating expenses in our consolidated statements
of operations. The management fee is currently reflected as the
‘LEH operating fee’ in our consolidated statements of
operations.
Jet Fuel Sales Agreement. LE sells jet fuel to LEH pursuant
to a Jet Fuel Sales Agreement. LEH resells the jet fuel purchased
from LE to a government agency. LEH bids for jet fuel contracts are
evaluated under preferential pricing terms due to its HUBZone
certification. The Jet Fuel Sales Agreement terminates on the
earliest to occur of: (a) a one-year term expiring March 31, 2020
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 refinery operations revenue in our
consolidated statements of operations.
Dock Tolling Agreement. In May 2016, LE entered a Dock
Tolling Agreement with LMT to facilitate loading and unloading of
petroleum products by barge at LMT’s dock facility in
Ingleside, Texas. The Dock Tolling Agreement had a five-year term.
Under the agreement, LE paid LMT a flat reservation fee monthly.
The reservation fee included tolling volumes up to 84,000 gallons
per day. Excess tolling volumes were subject to an increased per
gallon rate. The Dock Tolling Agreement was terminated effective
July 1, 2019. Amounts expensed as tolling fees under the Dock
Tolling Agreement are reflected in cost of goods sold in our
consolidated statements of operations.
Office Sub-Lease Agreement. In January 2018, BDSC entered
into an Office Space Agreement with LEH to lease office space at
our headquarters building in Houston, Texas. The Office Space
Agreement has a term of sixty-eight (68) months expiring on August
31, 2023. Under the Office Space Agreement, LEH’s base rent
is approximately $0.02 million per month. The Office Space
Agreement includes rent abatement periods.
Refinery Equipment Purchase. In July 2019, LE purchased two
(2) refurbished heat exchangers from LTRI. The total purchase price
was $160,000. The cost is reflected in accounts payable, related
party in our consolidated balance sheets.
Financial Agreements. We currently rely on LEH and its
affiliates (including Jonathan Carroll) to fund our working capital
requirements. LEH and its affiliates (Ingleside and Jonathan
Carroll) have provided working capital to Blue Dolphin in the form
of a term loan and non-cash advances (such as conversion of
accounts payable to debt under promissory notes). There can be no
assurance that LEH and its affiliates will continue to fund our
working capital requirements. Outstanding principal and accrued
interest owed under these financial agreements are reflected in
long-term debt, related party, current portion in our consolidated
balance sheets.
BDPL Loan Agreement (In Default). BDPL has a 2016 loan agreement and
related security agreement with LEH as lender (the “BDPL Loan
Agreement”). The BDPL Loan Agreement is currently in default
due to non-payment. Key terms of the BDPL Loan Agreement are as
follow:
|
Principal
Amount:
|
$4.0
million
|
|
Maturity
Date:
|
August
2018
|
|
Principal
and Interest Payment:
|
$500,000
annually
|
|
Interest
Rate:
|
16.00%
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
The
proceeds of the BDPL Loan Agreement were used for working capital.
There are no financial maintenance covenants associated with the
BDPL Loan Agreement. The BDPL Loan Agreement is secured by certain
property owned by BDPL. Outstanding principal owed to LEH under the
BDPL Loan Agreement is reflected in long-term debt, related party,
current portion in our consolidated balance sheets. Accrued
interest under the BDPL Loan Agreement is reflected in accrued
interest payable, related party, current portion in our
consolidated balance sheets. To date, there have been no payments
under the BDPL Loan Agreement.
Promissory Notes (In Default). Working capital provided to Blue
Dolphin in the form of non-cash advances whereby accounts payable,
related party was converted to debt under promissory notes are
reflected below. The promissory notes matured in January 2019.
Interest, which is compounded annually, is still accruing at a rate
of 8.00% and is reported as part of the outstanding balance.
Promissory notes to LEH, Ingleside and Jonathan Carroll, which are
reflected within long-term debt, related party, are currently in
default.
●
June LEH Note. The June LEH Note
reflects amounts owed to LEH at September 30, 2019 under the
Amended and Restated Operating Agreement.
●
March Ingleside Note. The March
Ingleside Note reflects amounts owed to Ingleside at September 30,
2019 under the Amended and Restated Tank Lease
Agreement.
●
March Carroll Note. The March Carroll
Note reflects amounts owed to Jonathan Carroll at September 30,
2019 under the guaranty fee agreements. See “Amended and
Restated Guaranty Fee Agreements” below for additional
information.
Amended and Restated Guaranty Fee Agreements. Jonathan
Carroll was required to provide a guarantee for repayment of funds
borrowed and interest accrued under certain LE and LRM
USDA-guaranteed loans. For his personal guarantee, LE and LRM each
entered a Guaranty Fee Agreement with Jonathan Carroll whereby he
earns a fee equal to 2.00% per annum of the outstanding principal
balance owed under the loan agreements. Effective in April 2017,
the Guaranty Fee Agreements were amended and restated (the
“Amended and Restated Guaranty Fee Agreements”) to
reflect payment 50% in cash and 50% in Blue Dolphin Common Stock.
Amounts owed to Jonathan Carroll under Amended and Restated
Guaranty Fee Agreements are reflected within long-term debt,
related party, current portion in our consolidated balance sheets.
Guaranty fees are recognized monthly
as incurred and are included in interest and other expense in our
consolidated statements of operations.
As
previously disclosed, the Lazarus Parties were prohibited by GEL
from making payments to Jonathan Carroll under the Amended and
Restated Guaranty Fee Agreements (see also “Note (18)
Commitments and Contingencies – Legal Matters – Final
Arbitration Award and Settlement Agreement”). Now that the
Settlement between GEL and the Lazarus Parties is final and
effective, management has resumed payments of the common stock
component to Mr. Carroll under the agreements. On November 14, 2019, Mr.
Carroll received 1,351,851 shares of Common Stock, which represents
payment of the common stock component of the guaranty fees for the
period May 2017 through October 2019. Mr. Carroll will receive
payment of the common stock component of the guaranty fees on a
quarterly basis going forward. Currently, management does not
intend on paying Mr. Carroll the cash portion due to Blue
Dolphin’s working capital deficits. The cash portion of
guaranty fees owed to Mr. Carroll will continue to be accrued and
added to the principal balance of the March Carroll
Note.
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Financial Statements Impact.
Consolidated Balance Sheets. Accounts payable, related party
to LMT associated with the Dock Tolling Agreement totaled $1.8
million and $1.5 million at September 30, 2019 and December 31,
2018, respectively. Accounts payable, related party to LTRI related
to the purchase of refinery equipment totaled $0.2 million and $0
at September 30, 2019 and December 31, 2018,
respectively.
Long-term
debt, related party, current portion and accrued interest payable,
related party, as of the dates indicated was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
|
|
|
June
LEH Note (in default)
|
$868
|
$611
|
|
BDPL
Loan Agreement (in default)
|
6,014
|
5,534
|
|
LEH
total
|
6,882
|
6,145
|
|
Ingleside
|
|
|
|
March
Ingleside Note (in default)
|
1,345
|
1,283
|
|
Jonathan
Carroll
|
|
|
|
March
Carroll Note (in default)
|
1,705
|
1,147
|
|
|
|
|
|
|
9,932
|
8,575
|
|
|
|
|
|
Less:
Long-term debt, related party, current portion, in
default
|
(7,918)
|
(7,041)
|
|
Less:
Accrued interest payable, related party (in default)
|
(2,014)
|
(1,534)
|
|
|
|
|
|
|
$-
|
$-
|
Consolidated Statements of Operations. Revenue from related
parties was as follows:
|
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
(in thousands, except percent amounts)
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
operations
|
|
|
|
|
|
|
|
|
|
LEH
|
$25,034
|
31.8%
|
$27,299
|
28.7%
|
$70,016
|
31.0%
|
$73,415
|
28.6%
|
|
Other
customers
|
52,503
|
66.8%
|
67,169
|
70.4%
|
152,636
|
67.6%
|
180,830
|
70.4%
|
|
Tolling and
terminaling
|
|
|
|
|
|
|
|
|
|
Other
customers
|
1,096
|
1.4%
|
1,075
|
0.9%
|
3,253
|
1.4%
|
2,659
|
1.0%
|
|
|
|
|
|
|
|
|
|
|
|
|
$78,633
|
100.0%
|
$95,543
|
100.0%
|
$225,905
|
100.0%
|
$256,904
|
100.0%
|
Fees
associated with the Dock Tolling Agreement with LMT totaled $0.05
million for the three months ended September 30, 2019 compared to
$0.2 million for the three months ended September 30, 2018. Fees
associated with the Dock Tolling Agreement with LMT totaled $0.4
million and $0.6 million for the nine-month periods ended September
30, 2019 and 2018, respectively.
Lease
payments received under the office sub-lease agreement with LEH
totaled $0.01 million for the three months ended September 30, 2019
and 2018. Lease payments received under the office sub-lease
agreement with LEH totaled $0.03 million for the nine months ended
September 30, 2019 and 2018.
The LEH
operating fee totaled approximately $0.1 million in the three
months ended September 30, 2019 compared to $0.2 million for the
three months ended September 30, 2018. For both nine-month periods
ended September 30, 2019 and 2018, the LEH operating fee totaled
approximately $0.5 million.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Interest
expense associated with the BDPL Loan Agreement, Amended and
Restated Guaranty Fee Agreements, and related-party promissory
notes (the June LEH Note, the March Ingleside Note, and the March
Carroll Note) for the periods indicated was as
follows:
|
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jonathan
Carroll
|
|
|
|
|
|
Guaranty
Fee Agreements
|
|
|
|
|
|
First
Term Loan Due 2034
|
$110
|
$114
|
$333
|
$344
|
|
Second
Term Loan Due 2034
|
46
|
47
|
138
|
141
|
|
March
Carroll Note (in default)
|
33
|
19
|
86
|
34
|
|
LEH
|
|
|
|
|
|
BDPL
Loan Agreement (in default)
|
160
|
160
|
480
|
482
|
|
June
LEH Note (in default)
|
17
|
6
|
40
|
7
|
|
Ingleside
|
|
|
|
|
|
March
Ingleside Note (in default)
|
12
|
25
|
63
|
96
|
|
|
|
|
|
|
|
|
$378
|
$371
|
$1,140
|
$1,104
|
|
(10)
|
Accrued Expenses and Other Current Liabilities
|
Accrued
expenses and other current liabilities as of the dates indicated
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unearned
revenue
|
$1,207
|
$434
|
|
Board
of director fees payable
|
370
|
273
|
|
Insurance
|
232
|
61
|
|
Other
payable
|
223
|
265
|
|
Property
taxes
|
161
|
48
|
|
Excise
and income taxes payable
|
93
|
47
|
|
Customer
deposits
|
10
|
109
|
|
Easement
payable
|
-
|
223
|
|
Accrued
rent
|
-
|
111
|
|
|
|
|
|
|
$2,296
|
$1,571
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
|
(11)
|
Long-Term Debt and Accrued Interest
|
Outstanding Balances. Our Long-term debt consists of: (i) a
LE $25.0 million loan with Veritex (the “First Term Loan Due
2034”), (ii) a LRM $10.0 million loan with Veritex (the
“Second Term Loan Due 2034”), and (iii) a LE loan with
Notre Dame Investors, Inc. as evidenced by a promissory note that
is currently held by John Kissick (the “Notre Dame
Debt”). As described within this “Note (11”)
Long-Term Debt and Accrued Interest,” certain of our
long-term debt is currently in default. See “Note (9)
Related-Party Transactions” for additional disclosures
regarding long-term debt, related party and accrued interest
payable, related party.
We
adopted new ASU guidance related to leases. As a result,
disclosures previously reported in this “Note (11”)
Long-Term Debt and Accrued Interest” as capital leases are
now reported in “Note (15) Leases” as finance leases.
See “Note (3) Significant Accounting Policies – New
Pronouncements Adopted” for information related to the new
lease accounting standard.
Long-term
debt, which represents outstanding principal and accrued interest,
as of the dates indicated was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Term Loan Due 2034 (in default)
|
$22,178
|
$22,593
|
|
Second
Term Loan Due 2034 (in default)
|
9,197
|
9,353
|
|
Notre
Dame Debt (in default)
|
8,418
|
7,821
|
|
Capital
lease
|
-
|
41
|
|
|
|
|
|
|
$39,793
|
$39,808
|
|
|
|
|
|
Less:
Current portion of long-term debt, net
|
(34,151)
|
(34,863)
|
|
Less:
Unamortized debt issue costs
|
(1,910)
|
(2,006)
|
|
Less:
Accrued interest payable (in default)
|
(3,732)
|
(2,939)
|
|
|
|
|
|
|
$-
|
$-
|
Unamortized
debt issue costs related to long-term debt as of the dates
indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Term Loan Due 2034 (in default)
|
$1,674
|
$1,674
|
|
Second
Term Loan Due 2034 (in default)
|
768
|
768
|
|
|
|
|
|
Less:
Accumulated amortization
|
(532)
|
(436)
|
|
|
|
|
|
|
$1,910
|
$2,006
|
Amortization
expense was $0.03 million for the three months ended September 30,
2019 and 2018. Amortization expense was $0.9 million for the nine
months ended September 30, 2019 and 2018.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Accrued interest related to long-term debt, which is reflected as
accrued interest payable in our consolidated balance sheets, as of
the dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notre
Dame Debt (in default)
|
$3,440
|
$2,843
|
|
First
Term Loan Due 2034 (in default)
|
182
|
43
|
|
Second
Term Loan Due 2034 (in default)
|
110
|
53
|
|
|
|
|
|
|
3,732
|
2,939
|
|
|
|
|
|
Less:
Accrued interest payable (in default)
|
(3,732)
|
(2,939)
|
|
|
|
|
|
Long-term
interest payable, net of current portion
|
$-
|
$-
|
USDA-Guaranteed Loans. The First Term Loan Due 2034 and
Second Term Loan Due 2034 are guaranteed 100% by the USDA. The
USDA, acting through its agencies, administers a federal rural
credit program that makes direct loans and guarantees portions of
loans made and serviced by USDA-qualified lenders for various
purposes. Each USDA guarantee is a full faith and credit obligation
of the United States with the USDA guaranteeing up to 100% of the
principal amount of guaranteed loans. The lender on each
USDA-guaranteed loan is required by regulation to retain the
unguaranteed portion of the guaranteed loan, to service the entire
underlying guaranteed loan, including the USDA-guaranteed portion
and the unguaranteed portion, and to remain mortgage and/or secured
party of record. The USDA-guaranteed portion and the unguaranteed
portion of the loan are to be secured by the same collateral with
equal lien priority. The USDA-guaranteed portion of a loan cannot
be paid later than, or in any way be subordinated to, the related
unguaranteed portion.
Amended and Restated Guaranty Fee Agreements. As a condition
of the First Term Loan Due 2034 and Second Term Loan Due 2034,
Jonathan Carroll was required to provide a guarantee for
repayment of funds
borrowed and interest accrued under the USDA-guaranteed loans. LEH,
LRM and Blue Dolphin also cross-guaranteed the First Term Loan Due
2034 and Second Term Loan Due 2034. (See “Note (9)
Related-Party Transactions” for additional disclosures
related to LEH, Jonathan Carroll, and the Amended and Restated
Guaranty Fee Agreements, as well as a breakdown of guaranty fee
expenses incurred related to the First Term Loan Due 2034 and
Second Term Loan Due 2034.)
Defaults in USDA-Guaranteed Loan Agreements. As described
elsewhere in this Quarterly Report, Veritex notified LE and LRM
that the Final Arbitration Award constituted an event of default
under the First Term Loan Due 2034 and the Second Term Loan Due
2034. In addition to existing events of default related to the
Final Arbitration Award, at September 30, 2019, 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
First Term Loan Due 2034 and Second Term Loan 2034. LE also failed
to replenish a payment reserve account as required under the First
Term Loan Due 2034. The occurrence of events of default under the
First Term Loan Due 2034 and Second Term Loan Due 2034 permits
Veritex to declare the amounts owed under the First Term Loan Due
2034 and Second Term Loan Due 2034 immediately due and payable,
exercise its rights with respect to collateral securing LE and
LRM’s obligations under the loan agreements, and/or exercise
any other rights and remedies available. Veritex did not accelerate or call due the First
Term Loan Due 2034 and Second Term Loan Due 2034 considering the
Settlement Agreement. Instead, Veritex expressly reserved
all its rights, privileges and remedies related to events of
default under the First Term Loan Due 2034 and Second Term Loan Due
2034 and informed LE and LRM that it would consider a final
confirmation of the Final Arbitration Award to be a material event
of default under the loan agreements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Veritex worked with LE and LRM and was aware and party to all
discussions and arrangements with GEL surrounding the
Settlement Agreement, all amendments, and the final and effective
Settlement with GEL. In the Veritex Consent, Veritex agreed to
waive certain covenant defaults and forbear from enforcing its
remedies under the secured loan agreements subject to: (i) the
agreement and concurrence of the USDA and (ii) the replenishment of
the $1.0 million payment reserve account as required under the
First Term Loan Due 2034 on or before August 31, 2019. As of the
filing date of this Quarterly Report, the payment reserve account
had not been fully replenished. Any exercise by Veritex of
its rights and remedies under the First Term Loan Due 2034 and
Second Term Loan Due 2034 would have a material adverse effect on
our business, financial condition, and results of operations. (See
“Note (1) Organization – Going Concern” and
“– Operating Risks” for additional disclosures
related to the First Term Loan Due 2034 and Second Term Loan Due
2034, the Final Arbitration Award and financial covenant
violations.)
Key Terms of Long-Term Debt.
First Term Loan Due 2034 (In Default). Key terms of the
First Term Loan Due 2034 are as follow:
|
Principal
Amount:
|
$25.0
million
|
|
Maturity
Date:
|
June
2034
|
|
Principal
and Interest Payment:
|
$0.2
million monthly
|
|
Interest
Rate:
|
Wall
Street Journal Prime Rate plus 2.75%
|
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,
which is 100% USDA-guaranteed, is secured by: (i) a first lien on
the Nixon Facility’s 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.
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.
Second Term Loan Due 2034 (In Default). Key terms of the
Second Term Loan Due 2034 are as follow:
|
Principal
Amount:
|
$10.0
million
|
|
Maturity
Date:
|
December
2034
|
|
Principal
and Interest Payment:
|
$0.1
million monthly
|
|
Interest
Rate:
|
Wall
Street Journal Prime Rate plus 2.75%
|
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, the funds of which were used to purchase idle
refinery equipment for refurbishment and use at the Nixon Facility.
Remaining proceeds are being used primarily to construct additional
new petroleum storage tanks at the Nixon Facility. The Second Term
Loan Due 2034, which is 100% USDA-guaranteed, is secured by: (i) a
second priority lien on the rights of LE in the crude distillation
tower 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 a
term loan that matured in 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.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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.
Notre Dame Debt (In Default). Key terms of the Notre Dame
Debt are as follow:
|
Original
Principal Amount:
|
$8.0
million
|
|
Additional
Principal:
|
$3.7
million
|
|
Maturity
Date:
|
January
2018
|
|
Principal
and Interest Payment:
|
None;
payment rights subordinated to senior lender
|
|
Default
Interest Rate:
|
16.00%
|
Pursuant
to a Sixth Amendment to the Notre Dame Debt, entered on November
14, 2017 and made effective September 18, 2017, the Notre Dame Debt
was amended to increase the principal amount by $3.7 million (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 $3.6 million. Pursuant to a
Subordination Agreement dated June 2015, the holder of the Notre
Dame Debt agreed to subordinate its right to payments, as well as
any security interest and liens on the Nixon Facility’s
business assets, in favor of Veritex as holder of the First Term
Loan Due 2034. To date, there have been no payments under the Notre
Dame Debt.
The
Notre Dame Debt is secured by a Deed of Trust, Security Agreement
and Financing Statements (the “Subordinated Deed of
Trust”), which encumbers the crude distillation tower and
general assets of LE. There are no financial maintenance
covenants associated with the Notre Dame Debt.
|
(12)
|
Line of Credit Payable
|
Line of
credit payable consists of a line of credit, guarantee and security
agreement between Pilot Travel Centers LLC (“Pilot”)
and NPS (the “Pilot Line of Credit”). Pilot and NPS
entered the Pilot Line of Credit on May 3, 2019. The parties to the
Pilot Line of Credit subsequently entered into amendments to the
Pilot Line of Credit on May 9, 2019 and May 10, 2019. The parties
entered into Amendment No. 1 to the Pilot Line of Credit effective
September 3, 2019 (the “Amended Pilot Line of Credit”).
The Amended Pilot Line of Credit was fully executed by all parties
on September 9, 2019. The Amended Pilot Line of Credit provided
for, among other things:
●
a $0.2 million
increase in the aggregate principal amount available under the line
of credit (from $12.8 million to $13.0 million); and
●
Pre-payment by NPS
to Pilot in a principal amount equal to the amount set forth
opposite such date below, together with accrued and unpaid interest
thereon:
|
Date
|
Principal
Amount
|
|
|
|
|
September
30, 2019
|
$0.1
million
|
|
October
31, 2019
|
$0.1
million
|
As of
the filing date of this Quarterly Report, the September and October
payments referenced above had been made.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Line of
credit payable, which represents outstanding principal and accrued
interest, as of the dates indicated was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amended
Pilot Line of Credit
|
$12,689
|
$-
|
|
|
|
|
|
Less:
Unamortized debt issue costs
|
(407)
|
-
|
|
Less:
Interest payable, short-term
|
(102)
|
-
|
|
|
|
|
|
|
$12,180
|
$-
|
Key
terms of the Amended Pilot Line of Credit are as
follow:
|
Principal
Amount:
|
Up to
$13.0 million
|
|
Maturity
Date:
|
May
2020
|
|
Monthly
Payment:
|
$0.1
million (September and October 2019 only)
|
|
Interest
Payment:
|
$0.2
million monthly
|
|
Interest
Rate:
|
12.00%
per annum
|
The
Amended Pilot Line of Credit was primarily used to fund the
Settlement Payment to GEL. Remaining funds are being used to
finance NPS' purchase of crude oil from Pilot pursuant to certain
purchase and supply contracts and to provide working capital. The
Amended Pilot Line of Credit contains customary affirmative and
negative covenants and events of default and is secured by (i) NPS
receivables, (ii) NPS assets, including a tank lease (the
“Tank Lease”), and (iii) LRM receivables. On May 3,
2019, as an inducement to Pilot’s entry into the Pilot Line
of Credit, Blue Dolphin and Pilot entered into a Pledge Agreement
(the “Pledge Agreement”) whereby Blue Dolphin pledged
its equity interests in NPS to Pilot to secure NPS’
obligations under the Pilot Line of Credit. Blue Dolphin, LE, LRM,
and LEH have each guaranteed NPS’ obligations under the Pilot
Line of Credit. On May 10, 2019, LE, NPS, Pilot and Veritex entered
into a Subordination and Attornment Agreement (the
“Subordination Agreement”), providing that, if Veritex
in its capacity as a secured lender of LE and LRM were to foreclose
on LE property that NPS was leasing from LE pursuant to the Tank
Lease, Veritex would permit the continued performance of
obligations under the Tank Lease so long as certain conditions are
met. The effectiveness of the Subordination Agreement is subject to
certain conditions, including the agreement and concurrence of the
USDA.
|
(13)
|
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, and we
depreciated the amount added to property and equipment and
recognized accretion expense relating to the discounted liability
over the remaining life of the asset. At December 31, 2018, the
liability was fully accreted.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Due to
the length of inactivity of our pipelines and facilities assets,
BDPL is required by the Bureau of Ocean Energy Management
(“BOEM”) to abandon-in-place certain pipelines and
remove an anchor platform in federal waters. Members of management
met with BOEM and the Bureau of Safety and Environmental
Enforcement (“BSEE”) on August 15, 2019. BSEE mandated
BDPL to submit permit applications for pipeline and platform
decommissioning within six (6) months (no later than February 15,
2020), and to develop and implement a safe boarding plan for
submission with such permit applications. Further, BDPL must
conduct approved, permitted work within 12 months (no later than
August 15, 2020). If these actions are not addressed within
the allowable timeframes, BOEM indicated that BDPL will be subject
to vigorous regulatory oversight and enforcement, including but not
limited to failure to correct INCs, civil penalties, and revocation
of BDPL’s operator designation. As of the filing date of this
Quarterly Report, BDPL engaged a third-party consultant to oversee
the abandonment project, and the consultant is preparing the permit
applications for submittal to BSEE. If BDPL is unable to comply
within BSEE’s designated timetables and is assessed
significant penalties by BSEE, we will experience a significant and
material adverse effect on our operations, liquidity, and financial
condition. Plugging and abandonment costs will be recorded during
the period incurred or as information becomes available to
substantiate actual and/or probable costs.
Changes
to our ARO liability for the periods indicated were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligations, at the beginning of the period
|
$2,580
|
$2,315
|
|
Accretion
expense
|
-
|
265
|
|
|
2,580
|
2,580
|
|
Less:
asset retirement obligations, current portion
|
(2,580)
|
(2,580)
|
|
|
|
|
|
Long-term
asset retirement obligations, at the end of the period
|
$-
|
$-
|
|
(14)
|
Concentration of Risk
|
Bank Accounts. Financial instruments that potentially
subject us to concentrations of risk consist primarily of cash,
trade receivables and payables. We maintain our cash balances at
financial institutions located in Houston, Texas. In the U.S., the
Federal Deposit Insurance Corporation (the “FDIC”)
insures certain financial products up to a maximum of $250,000 per
depositor. At September 30, 2019 and December 31, 2018, we had cash
balances (including restricted cash) of more than the FDIC
insurance limit per depositor in the amount of $0.4 million and
$1.2 million, respectively.
Key Supplier. Operation of the Nixon refinery depends on our
ability to purchase adequate amounts of crude oil and condensate,
which is primarily dependent on our liquidity and access to
capital. We have a long-term crude supply contract in place with
Pilot. In connection with the crude supply contract, Pilot stores
its crude oil at the Nixon Facility pursuant to a terminal services
agreement. Pilot currently provides us with adequate amounts of
crude oil and condensate on favorable terms, and we expect Pilot to
continue to do so for the foreseeable future. Our ability to purchase adequate amounts of crude
oil and condensate could be adversely affected by net
losses, working capital deficits, and financial covenant defaults
in secured loan agreements.(See “Note
(19) Subsquent Event” for
additional disclosures related to the crude supply
contract.)
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, 2019, we had 4 customers that
accounted for approximately 98% 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, 2019, these 4 customers
represented approximately $0.6 million in accounts
receivable. LEH represented approximately $0.3 million
in accounts receivable. LEH purchases our jet fuel and resells the
jet fuel to a government agency. LEH bids for jet fuel contracts
are evaluated under preferential pricing terms due to its HUBZone
certification. (See “Note (9) Related-Party
Transactions,” “Note (11) Long-Term Debt and Accrued
Interest,” and “Note (18) Commitments and Contingencies
– Financing Agreements” for additional disclosures
related to LEH.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
For the
nine months ended September 30, 2019, we had 4 customers that
accounted for approximately 98% of our refined petroleum product
sales. LEH was 1 of these 4 significant customers and accounted for
approximately 31% of our refined petroleum product
sales. At September 30, 2019, these 4 customers
represented approximately $0.6 million in accounts
receivable. LEH represented approximately $0.3 million
in accounts receivable.
For the
three months ended September 30, 2018, we had 4 customers that
accounted for approximately 94% of refinery operations revenue.
LEH, a related party, was 1 of these 4 significant customers and
accounted for approximately 29% of refinery operations revenue. At
September 30, 2018, these 4 customers represented approximately
$1.3 million in accounts receivable. LEH represented approximately
$0 in accounts receivable.
For the
nine months ended September 30, 2018, we had 4 customers that
accounted for approximately 90% of our refined petroleum product
sales. LEH was 1 of these 4 significant customers and accounted for
approximately 29% of our refined petroleum product
sales. At September 30, 2018, these 4 customers
represented approximately $1.3 million in accounts
receivable. LEH represented approximately $0 in accounts
receivable.
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 occasionally
sell low-sulfur diesel to customers that export to Mexico. 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,
|
|
|
|
|
|
|
|
|
(in thousands,
except percent amounts)
|
|
|
|
|
|
|
|
|
|
|
|
LPG
mix
|
$8
|
0.0%
|
$-
|
0.0%
|
$17
|
0.0%
|
$3
|
0.0%
|
|
Naphtha
|
14,147
|
18.2%
|
24,127
|
25.5%
|
43,358
|
19.5%
|
64,093
|
25.2%
|
|
Jet
fuel
|
25,035
|
32.3%
|
27,299
|
28.9%
|
70,017
|
31.4%
|
73,415
|
28.9%
|
|
HOBM
|
17,044
|
22.0%
|
21,735
|
23.0%
|
49,951
|
22.5%
|
60,594
|
23.8%
|
|
AGO
|
21,303
|
27.5%
|
21,307
|
22.6%
|
59,309
|
26.6%
|
56,140
|
22.1%
|
|
|
|
|
|
|
|
|
|
|
|
|
$77,537
|
100.0%
|
$94,468
|
100.0%
|
$222,652
|
100.0%
|
$254,245
|
100.0%
|
We
adopted the new lease accounting guidance using the modified
retrospective method and applied it to all leases based on the
contract terms in effect as of January 1, 2019. For existing
contracts, we carried forward our historical assessment of: (i)
whether contracts are or contain leases, (ii) lease classification,
and (iii) initial direct costs.
As of
September 30, 2019, leases were as follow:
●
Office Lease (Operating Lease). BDSC
has an office lease related to our principal office space in
Houston, Texas. The 68-month operating lease expires in 2023. BDSC
has the option to extend the lease term for one additional five (5)
year period if notice of intent to extend is provided to the lessor
at least twelve (12) months before the end of the current term. LEH
subleases a portion of this leased office space (see “Note
(9) Related-Party Transactions” related to the LEH office
sub-lease agreement). Sublease income received from LEH
totaled $0.01 million for both three-month periods ended September
30, 2019 and 2018. Sublease income received from LEH totaled $0.03
million for both nine-month periods ended September 30, 2019 and
2018.
●
Crane (Finance Lease). In January 2018,
LE entered a 24-month lease for the purchase of a 20-ton crane for
use at the Nixon Facility. The lease requires a negligible monthly
payment and matures in January 2020.
●
Backhoe Rent-to-Own Agreement (Finance
Lease). In May 2019, LE entered into a 12-month
equipment rental agreement with the option to purchase the backhoe
at maturity. The backhoe is being used at the Nixon
Facility.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
For
leases with terms greater than 12 months, including renewal options
when appropriate, we record the related right-of-use asset and
lease liability as the present value of the fixed lease payments
over the lease term. Since the leases do not provide a
readily-determinable discount rate, we use the incremental
borrowing rate to discount lease payments to present value. The
following table presents the lease-related assets and liabilities
recorded on the consolidated balance sheet:
|
|
Classification on
|
|
|
|
Consolidated Balance Sheet
|
|
|
|
|
|
|
Assets
|
|
|
|
Operating
lease right-of-use assets
|
Operating
lease right-of-use assets
|
$787
|
|
Less:
Accumulated amortization on operating lease assets
|
Operating
lease right-of-use assets
|
(102)
|
|
|
685
|
|
|
|
|
Finance
lease assets
|
Property
and equipment, net
|
180
|
|
Less:
Accumulated amortization on finance lease assets
|
Property
and equipment, net
|
(26)
|
|
|
154
|
|
|
|
|
Total
lease assets
|
|
$839
|
|
|
|
|
Liabilities
|
|
|
|
Current
|
|
|
|
Operating
lease
|
Current
portion of lease liabilities
|
$172
|
|
Finance
leases
|
Current
portion of lease liabilities
|
90
|
|
|
262
|
|
Noncurrent
|
|
|
|
Operating
lease
|
Long-term
lease liabilities, net of current
|
610
|
|
Total
lease liabilities
|
|
$872
|
|
Weighted
average remaining lease term in years
|
|
Operating
lease
|
3.92
|
|
Finance
leases
|
0.59
|
|
Weighted
average discount rate
|
|
|
Operating
lease
|
8.25%
|
|
Finance
leases
|
8.25%
|
The
following table presents information related to lease costs for
operating and finance leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
lease costs
|
$51
|
$154
|
|
Finance
lease costs:
|
|
|
|
Depreciation
of leased assets
|
4
|
12
|
|
Interest
on lease liabilities
|
2
|
4
|
|
Total
lease cost
|
$57
|
$170
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
The
table below presents supplemental cash flow information related to
leases as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for amounts included in the measurement of lease
liabilities:
|
|
|
|
Operating
cash flows for operating lease
|
$40
|
$81
|
|
Operating
cash flows for finance leases
|
2
|
4
|
|
Financing
cash flows for finance leases
|
13
|
35
|
As of
September 30, 2019, maturities of lease liabilities for the periods
indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
$172
|
$17
|
$189
|
|
2021
|
189
|
73
|
262
|
|
2022
|
209
|
-
|
209
|
|
2023
|
212
|
-
|
212
|
|
|
|
|
|
|
|
$782
|
$90
|
$872
|
As of
September 30, 2019, our future minimum annual lease commitments
that are non-cancelable for the periods indicated are as
follow:
|
|
|
|
|
|
|
|
|
|
2020
|
$230
|
|
2021
|
233
|
|
2022
|
236
|
|
2023
|
219
|
|
|
|
|
|
$918
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
The
provision for income tax benefit for the periods indicated was as
follows:
|
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
Federal
|
$-
|
$-
|
$-
|
$108
|
|
State
|
-
|
-
|
-
|
-
|
|
Deferred
|
|
|
|
|
|
Change
in valuation allowance
|
-
|
-
|
-
|
109
|
|
|
|
|
|
|
|
Total
provision for income taxes
|
$-
|
$-
|
$-
|
$217
|
The
state of Texas has a Texas margins tax (“TMT”), which
is a form of business tax imposed on gross margin. Although TMT is
imposed on an entity’s gross profit rather than on its net
income, certain aspects of TMT make it like an income tax.
Accordingly, TMT is treated as an income tax for financial
reporting purposes.
Effective Tax Rate. Beginning in 2018, our effective tax
rate differed from the U.S. federal statutory rate primarily due to
AMT credits made refundable by the Tax Cuts and Jobs Act. At the
date of enactment of the Tax Cuts and Jobs Act, we re-measured our
deferred tax assets and liabilities using a rate of 21%, which is
the rate expected to be in place when such deferred assets and
liabilities are expected to reverse in the future. The
re-measurement was offset by a change in our valuation allowance,
resulting in there being no impact on our net deferred tax
assets.
Deferred
income taxes as of the dates indicated consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
tax assets:
|
|
|
|
Net
operating loss and capital loss carryforwards
|
$12,618
|
$11,260
|
|
Accrued
arbitration award payable
|
-
|
2,850
|
|
Business
interest expense
|
1,695
|
704
|
|
Start-up
costs (crude oil and condensate processing facility)
|
615
|
678
|
|
Asset
retirement obligations liability/deferred revenue
|
541
|
542
|
|
AMT
credit and other
|
50
|
108
|
|
Total
deferred tax assets
|
15,519
|
16,142
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
Basis
differences in property and equipment
|
(5,767)
|
(5,153)
|
|
Total
deferred tax liabilities
|
(5,767)
|
(5,153)
|
|
|
|
|
|
|
9,752
|
10,989
|
|
|
|
|
|
Valuation
allowance
|
(9,702)
|
(10,881)
|
|
|
|
|
|
Deferred
tax assets, net
|
$50
|
$108
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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 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 fifty
(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 approximately $0.6 million per year. Unused portions of the
annual use limitation amount may be used in subsequent years.
Because 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 and prior to 2018 are not subject
to an annual use limitation under IRC Section 382 and may be used
for a period of 20 years in addition to available amounts of NOL
carryforwards generated prior to the ownership change. NOL
carryforwards that were generated after 2017 may only be used to
offset 80% of taxable income and are carried forward
indefinitely.
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, 2017
|
$9,614
|
$30,219
|
$39,833
|
|
|
|
|
|
|
Net
operating losses
|
-
|
7,116
|
7,116
|
|
|
|
|
|
|
Balance
at December 31, 2018
|
$9,614
|
$37,335
|
$46,949
|
|
|
|
|
|
|
Net
operating losses
|
-
|
6,460
|
6,460
|
|
|
|
|
|
|
Balance
at September 30, 2019
|
$9,614
|
$43,795
|
$53,409
|
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, 2019 and December 31, 2018,
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 valuation allowance against the deferred tax assets for
which realization was not deemed more likely than not as of
September 30, 2019 and December 31, 2018.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
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,
|
|
|
|
|
|
|
|
|
(in thousands, except share and per share amounts)
|
|
|
|
|
|
|
|
Net
income (loss)
|
$8,167
|
$(937)
|
$5,615
|
$748
|
|
|
|
|
|
|
|
Basic
and diluted income (loss) per share
|
$0.74
|
$(0.09)
|
$0.51
|
$0.07
|
|
|
|
|
|
|
|
Basic
and Diluted
|
|
|
|
|
|
Weighted
average number of shares of
|
|
|
|
|
|
common
stock outstanding and potential
|
|
|
|
|
|
dilutive
shares of common stock
|
10,975,514
|
10,925,513
|
10,975,514
|
10,925,513
|
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 three and nine months ended
September 30, 2019 and 2018 was the same as basic EPS as there were
no stock options or other dilutive instruments
outstanding.
|
(18)
|
Commitments and Contingencies
|
Legal Matters.
Final Arbitration Award and Settlement Agreement.
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 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 of LE’s claims against GEL
and granted substantially all the relief requested by GEL in its
counterclaims. Among other matters, the Final Arbitration Award
awarded damages and GEL’s attorneys’ fees and related
expenses to GEL in the aggregate amount of $31.3
million.
In July
2018, the Lazarus Parties and GEL entered into the Settlement
Agreement. The Settlement Agreement was subsequently amended five
times to extend the Settlement Payment Date and/or modify certain
terms related to the Interim Payments or the Settlement Payment.
During the period September 2017 to August 2019, GEL received the
following amounts from the Lazarus Parties to reduce the
outstanding balance of the Final Arbitration Award:
|
(in
millions)
|
|
|
|
|
Initial payment
(September 2017)
|
$3.7
|
|
Interim Payments
(July 2018 to April 2019)
|
8.0
|
|
Settlement Payment
(Multiple Payments May 7 to 10, 2019)
|
10.0
|
|
Deferred Interim
Installment Payments (June 2019 to August 2019)
|
0.5
|
|
|
|
|
|
$22.2
|
The
Lazarus Parties made all payments to GEL as required for the
Settlement to be final and effective. As a result: (i) the
Settlement occurred on August 23, 2019, (ii) the mutual releases
became effective, (iii) GEL filed a stipulation of dismissal of
claims against LE, and (iv) Blue Dolphin recognized a $9.1 million
gain on the extinguishment of debt on its consolidated statements
of operations for the three and nine months ended September 30,
2019. Until the Settlement occurred, the debt was reflected on Blue
Dolphin’s consolidated balance sheets as accrued arbitration
award payable. At September 30, 2019 and December 31, 2018, accrued
arbitration award payable was $0 and $21.1million,
respectively.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Veritex Secured Loan Agreement Events of Default. See
“Note (1) Organization – Going Concern – Defaults
under Secured Loan Agreements” and “Note (11) Long-Term
Debt and Accrued Interest” for disclosures related to
defaults under Veritex secured loan agreements.
Other Legal Matters. We are involved in lawsuits, claims,
and proceedings incidental to the conduct of our business,
including mechanic’s liens, contract-related disputes,
administrative proceedings, and financial assurance (bonding)
requirements with regulatory bodies. Management is in discussion
with all concerned parties and does not believe that such matters
will have a material adverse effect on our financial position,
earnings, or cash flows. However,
there can be no assurance that such discussions will result in a
manageable outcome or that we will be able to meet financial
assurance (bonding) requirements. If Veritex exercises its rights
and remedies under the secured loan agreements, our business,
financial condition, and results of operations will be materially
adversely affected.
Amended and Restated Operating Agreement. See “Note
(9) Related-Party Transactions” for additional disclosures
related to the Amended and Restated Operating
Agreement.
Financing Agreements. See “Note (11) Long-Term Debt
and Accrued Interest” and “Note (12) Line of Credit
Payable” for additional disclosures related to financing
agreements.
Guarantees. LEH and Jonathan Carroll provided guarantees on
certain Blue Dolphin-related long-term debt. The maximum amount of
any guarantee is reduced as payments are made. See “Note (11)
Long-Term Debt and Accrued Interest” for additional
disclosures related to guarantees.
Health, Safety and Environmental Matters. Our operations 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
products 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 air 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 at 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 a
petroleum storage tank.
Supplemental Pipeline Bonds. In a letter dated March 30,
2018, BOEM ordered BDPL to provide additional supplemental bonds or
acceptable financial assurance of approximately $4.8 million (the
“Separate Orders”) within sixty (60) calendar days of
receipt of the letter. The Separate Orders relate to five (5)
existing pipeline rights-of-way. BOEM issued an Incident of
Noncompliance (“INC”) for each Separate Order dated
June 8, 2018 (the “June 2018 INCs”) and received by
BDPL on June 11, 2018. BOEM asserts that the June 2018 INCs
authorize BOEM to impose financial penalties on BDPL if it does not
comply with the Separate Orders within twenty (20) days. BOEM
asserts that potential penalties accrue for each day BDPL failed to
comply after June 28, 2018. BDPL appealed the June 2018
INCs on August 8, 2018. The Interior Board of Land Appeals (the
“IBLA”) granted multiple extension requests that
extended BDPL’s deadline for filing a Statement of Reasons.
On August 9, 2019, BDPL timely filed its Statement of Reasons with
the IBLA. On October 16, 2019, BOEM filed a motion requesting a
30-day extension to file its answer to BDPL’s Statement of
Reasons. BOEM filed its answer to BDPL’s Statement of
Reasons, requesting that the IBLA affirm the June 2018 INCs. In
light of BDPL’s August 2018 meeting with BSEE, BDPL intends
to request a stay in the IBLA matter until August 2020. The Office
of the Solicitor of the U.S. Department of the Interior (the
“Solicitor's
Office”) was
agreeable to a 10-day extension while it conferred with BOEM on
BDPL’s stay request. On October 31, 2019, BDPL filed a motion
to request the 10-day extension, which motion was subsequently
granted by the IBLA. The Solicitor's Office consented to an
additional 14-day extension, until November 22, 2019, for BDPL to
file its reply. On November 8, 2019, BDPL filed a motion to request
the 14-day extension.
BDPL’s
pending appeal of the June 2018 INCs does not relieve BDPL of its
obligations to provide additional financial assurance in accordance
with the Separate Orders, or of BOEM’s authority to impose
financial penalties. Members of management met with BOEM and BSEE
on August 15, 2019. Based upon discussions with BOEM, BDPL
reasonably expects that its pipeline and platform decommissioning
obligations, including incremental amounts of supplemental bonds,
can be significantly reduced or eliminated, which may serve to
partially or fully resolve the Separate Orders and the June 2018
INCs (see “Idle Iron” discussion below). As of
September 30, 2019 and December 31, 2018, BDPL maintained
approximately $0.9 million in credit and cash-backed pipeline
rights-of-way bonds issued to the BOEM. If BDPL is required by BOEM
to provide significant additional supplemental bonds or additional
financial assurance or is assessed significant penalties under the
June 2018 INCs, we will experience a significant and material
adverse effect on our operations, liquidity, and financial
condition. At this time, we are unable to predict the outcome of
the Separate Orders. Accordingly, we have not recorded a liability
on our consolidated balance sheet as of September 30,
2019.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
|
Notes
to Consolidated Financial Statements (Continued)
|
Idle Iron. BSEE requires operators to decommission certain
wells and platforms that have not been used in the past five (5)
years for exploration and development operations or as
infrastructure to support such operations. BDPL’s Blue
Dolphin Pipeline has been inactive since September 2012. Due to the
length of inactivity, BSEE required BDPL to: (i) flush and fill the
Blue Dolphin Pipeline, (ii) abandon-in-place a portion of the Blue
Dolphin Pipeline’s 20” segment and certain smaller
diameter connecting lateral lines that reside offshore in federal
waters and (iii) remove from federal waters the GA-288C anchor
platform. In April 2016, BDPL submitted decommissioning permit
applications to BSEE for three (3) pipeline segments –
Segments #13101, #9428, and #15635 – and the GA-288C anchor
platform. In June 2016, BDPL also submitted a decommissioning
permit application to the U.S. Army Corps of Engineers
(“USCOE”) for abandonment of Segment #9428. The permit
applications were granted by BSEE at varying dates between August
2016 and April 2017. Work must typically be completed within 120
days from the date of permit approval. The USCOE withdrew
BDPL’s decommissioning permit application in April
2018.
In a
letter dated December 19, 2018, BSEE issued to BDPL an INC for its
failure to flush and fill Segment #13101 (the “December 2018
INC”) pursuant to the pipeline decommissioning approval
letter issued in March 2017. Members of management met with BOEM
and BSEE on August 15, 2019. BSEE proposed that BDPL submit permit
applications for pipeline and platform decommissioning within six
(6) months (no later than February 15, 2020), and to develop and
implement a safe boarding plan for submission with such permit
applications. Further, BSEE proposed that BDPL would need to
conduct approved, permitted work in a safe manner within 12 months
(no later than August 15, 2020). If these actions are not
addressed within the allowable timeframes, BOEM indicated that BDPL
would be subject to vigorous regulatory oversight and enforcement,
including but not limited to failure to correct INCs, civil
penalties, and revocation of BDPL’s operator designation. As
of the filing date of this Quarterly Report, BDPL engaged a
third-party consultant to oversee the abandonment project, and the
consultant is preparing the permit applications for submittal to
BSEE. If BDPL is unable to comply within BSEE’s designated
timetables and is assessed significant penalties by BSEE, we may
experience a significant and material adverse effect on our
operations, liquidity, and financial condition. As of September 30,
2019, BDPL maintained $2.6 million in asset retirement obligations
related to abandonment of these assets.
On
November 11, 2019, LE entered into a long-term crude supply
contract with Pilot. The crude supply contract has a volume-based,
initial term of approximately 24.8 million bbls, after which time
the contract renews on a 1-year evergreen basis until either party
terminates the contract. Pilot may terminate the contract by giving
LE sixty (60) days prior written notice at any time during the term
of the contract. LE may terminate the contract upon expiration of
the initial term or at any time during a renewal term by giving
Pilot sixty (60) days prior written notice. As consideration for LE
entering into the crude supply contract for an extended term, Pilot
paid LE a one-time payment of $2.5 million.
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
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, 2019 (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 periods ended March
31, 2019 and June 30, 2019, as well as our Annual Report on Form
10-K for the fiscal year ended December 31, 2018 (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
●
Inadequate
liquidity to sustain operations due to net losses, working capital
deficits, and other factors, including defaults under secured loan
agreements, any of which could have a material adverse effect on
us.
●
Defaults under our
secured loan agreements could have a material adverse effect on our
business, financial condition, and results of operations and
materially adversely affect the value of an investment in our
common stock.
●
Our substantial
debt in the current portion of long-term debt, which is currently
in default, could adversely affect our financial health and make us
more vulnerable to adverse economic conditions.
●
Our business,
financial condition and operating results may be adversely affected
by increased costs of capital or a reduction in the availability of
credit.
●
LEH holds a
significant interest in us, and related-party transactions with LEH
and its affiliates may cause conflicts of interest that may
adversely affect us.
●
The dangers
inherent in oil and gas operations could expose us to potentially
significant losses, costs, or liabilities and reduce our
liquidity.
●
The geographic
concentration of our assets creates a significant exposure to the
risks of the regional economy and other regional adverse
conditions.
●
Competition from
companies having greater financial and other resources could
materially and adversely affect our business and results of
operations.
●
Environmental laws
and regulations could require us to make substantial capital
expenditures to remain in compliance or to remediate current or
future contamination that could give rise to material
liabilities.
●
We are subject to
strict laws and regulations regarding personnel and process safety,
and failure to comply with these laws and regulations could have a
material adverse effect on our results of operations, financial
condition and profitability.
●
Our insurance
policies may be inadequate or expensive.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
●
Our ability to use
net operating loss (“NOL”) carryforwards to offset
future taxable income for U.S. federal income tax purposes is
subject to limitation.
●
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 Operations
●
Management has
determined that there is, and the report of our independent
registered public accounting firm expresses, substantial doubt
about our ability to continue as a going concern.
●
Refining margins
are volatile, and a reduction in refining margins will adversely
affect the amount of cash we will have available for working
capital.
●
The price
volatility of crude oil, other feedstocks, refined petroleum
products, and fuel and utility services may have a material adverse
effect on our earnings, cash flows and liquidity.
●
Our future success
depends on our ability to acquire adequate crude oil levels on
favorable terms to operate the Nixon refinery.
●
Downtime at the
Nixon refinery could result in lost margin opportunity, increased
maintenance expense, increased inventory, and a reduction in cash
available for payment of our debt obligations.
●
We may have capital
needs for which our internally generated cash flows and other
sources of liquidity may not be adequate. Further, LEH and its
affiliates (including Jonathan Carroll) may, but are not required
to, fund our working capital requirements in the event our
internally generated cash flows and other sources of liquidity are
inadequate.
●
Our business may
suffer if any of the executive officers or other key personnel
discontinue employment with us. Furthermore, a shortage of skilled
labor or disruptions in our labor force may make it difficult for
us to maintain productivity.
●
Loss of market
share by a key customer, one of which is LEH, or consolidation
among our customer base could harm our operating
results.
●
The sale of refined
petroleum products to the wholesale market is our primary business,
and if we fail to maintain and grow the market share of our refined
petroleum products, our operating results could
suffer.
●
We are dependent on
third parties for the transportation of crude oil and condensate
into and refined petroleum products out of our Nixon Facility, and
if these third parties become unavailable to us, our ability to
process crude oil and condensate and sell refined petroleum
products to wholesale markets could be materially and adversely
affected.
●
Our suppliers
source a substantial amount, if not all, of our crude oil and
condensate from the Eagle Ford Shale and may experience
interruptions of supply from that region.
●
Our refining
operations and customers are primarily located within the Eagle
Ford Shale and changes in the supply/demand balance in this region
could result in lower refining margins.
●
Regulation of
greenhouse gas emissions could increase our operational costs and
reduce demand for our products.
Risks Related to Our Pipelines and Oil and Gas
Properties
●
Assessment of civil
penalties by BOEM for failure to satisfy orders to increase
supplemental pipeline bonds could significantly impact our
operations, liquidity, and financial condition.
●
Assessment of civil
penalties by BSEE for failure to decommission platform and pipeline
assets within a prescribed time period could significantly impact
our operations, liquidity, and financial condition.
●
More stringent
requirements imposed by BOEM and BSEE related to the
decommissioning, plugging, and abandonment of wells, platforms, and
pipelines could materially increase our estimate of 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.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Going Concern
See
“Part I, Item 1. Financial Statements – Note (1)
Organization – Going Concern” regarding factors
management has determined raise
substantial doubt about our ability to continue as a going
concern.
Operating Risks
See
“Part I, Item 1. Financial Statements – Note (1)
Organization – Operating Risks” regarding factors that
have negatively impacted execution of our business
plan.
Company Overview
Blue
Dolphin is a publicly traded Delaware corporation primarily engaged
in the refining and marketing of petroleum products. We also
provide tolling and storage terminaling services. Our assets, which
are in Nixon, Texas, primarily include a 15,000-bpd crude
distillation tower and more than 1.0 million bbls of petroleum
storage tanks (collectively the “Nixon Facility”).
Pipeline transportation and oil and gas operations are no longer
active. Blue Dolphin maintains a website at
http://www.blue-dolphin-energy.com. Information on or
accessible through Blue Dolphin’s website is not incorporated
by reference in or otherwise made a part of this Quarterly
Report.
Major Influences on Results of Operations
Refinery Operations
As a
margin-based business, our refinery operations are primarily
affected by gross profit per bbl, product slate, and refinery
downtime.
Price Differentials per Bbl
Gross
profit per bbl, which reflects the dollar per bbl price difference
between crude oil and condensate (input) and refined petroleum
products (output), is the most significant driver of refining
margins, and they have historically been subject to wide
fluctuations. Our per bbl cost to acquire crude oil and condensate
and the dollar per bbl 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
Product Slate
Management periodically determines whether to change the
refinery’s 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.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Refinery Downtime
The safe and reliable operation of the refinery 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 refinery 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 refinery 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 will
result in lost margin opportunity, potential increased maintenance
expense, and a reduction of refined petroleum products inventory,
which could reduce our ability to meet our payment
obligations.
Tolling and Terminaling Operations
The Nixon Facility’s petroleum storage tanks and
infrastructure are primarily suited for crude oil and condensate
and refined petroleum products, such as naphtha, jet fuel, diesel
and fuel oil. Our storage terminaling operations are primarily
affected by:
●
price
(in terms of storage fees);
●
industry
factors, including changes in the prices of petroleum products that
affect demand for storage services; and
●
utilization
rates of our competitors (local demand).
Key Relationships
Relationship with LEH
Blue
Dolphin and certain of its subsidiaries are currently parties to a
variety of agreements with LEH and its affiliates and a
counter-party. Related-party agreements with LEH include: (i) an
Amended and Restated Operating Agreement with Blue Dolphin and LE,
(ii) a Jet Fuel Sales Agreement with LE, (iii) a Loan Agreement
with BDPL, (iv) an Amended and Restated Promissory Note with Blue
Dolphin, and (v) an office sub-lease agreement with BDSC. 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 (9)
Related-Party Transactions” for additional disclosures
related to agreements that we have in place with LEH and its
affiliates.)
Relationship with Crude Supplier
Operation
of the Nixon refinery depends on our ability to purchase adequate
amounts of crude oil and condensate, which is primarily dependent
on our liquidity and access to capital. We have a long-term crude
supply contract in place with Pilot Travel Centers LLC ("Pilot").
In connection with the crude supply contract, Pilot stores its
crude oil at the Nixon Facility pursuant to a terminal services
agreement. Pilot currently provides us with adequate amounts of
crude oil and condensate on favorable terms, and we expect Pilot to
continue to do so for the foreseeable future. Our ability to
purchase adequate amounts of crude oil and condensate could be
adversely affected by net losses, working capital deficits, and
financial covenant defaults in secured loan agreements.
(See
“Part I, Item 1. Financial Statements - Note
(19) Subsequent Event” for additional disclosures related to the
crude supply
contract.)
Management
believes that it is taking the appropriate steps to improve our
operations and financial stability. If our business strategy is
unsuccessful, it could affect our ability to acquire adequate
supplies of crude oil and condensate under the existing contract or
otherwise.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Results of Operations
Certain
Prior Quarter and Prior Nine Month amounts as defined herein have
been reclassified in order to conform to the Current Quarter
presentation. Specifically, certain changes to the presentation of
prior period statements of operations have been made to conform to
the current period presentation, primarily relating to: (i) a
retitling from ‘cost of sales’ to ‘cost of goods
sold,’ which includes all costs directly attributable to the
generation of the related revenue, as defined by GAAP and (ii) a
breakout of the ‘LEH operating fee’ under the Amended
and Restated Operating Agreement, which was previously reported
within ‘refinery operating expenses’. These changes had
no effect on the reported results of operations.
Consolidated Results
Three Months Ended September 30, 2019 (the “Current
Quarter”) Compared to September 30, 2018 (the “Prior
Quarter”).
Total Revenue from Operations. For the Current Quarter, we
had total revenue from operations of $78.6 million compared to
total revenue from operations of $95.5 million for the Prior
Quarter, a decrease of nearly 18%. Approximately 99% of our revenue
is derived from refinery operations while 1% is derived from
tolling and terminaling. Refinery operations revenue decreased
approximately $16.9 million in the Current Quarter compared to the
Prior Quarter. The decrease in refinery operations revenue was due
to lower commodity pricing per bbl on refined petroleum products
sold and slightly lower sales volume in the Current Quarter
compared to the Prior Quarter. Tolling and terminaling revenue was
relatively flat at $1.0 million for both the Current Quarter and
the Prior Quarter.
Total Cost of Goods Sold. Total cost of goods sold was $76.2
million for the Current Quarter compared to $94.1 million for the
Prior Quarter. The 19% decrease in total cost of goods sold in the
Current Quarter compared to the Prior Quarter related to lower
commodity prices per bbl for crude oil and chemicals and slightly
decreased throughput volume.
Gross Profit (Loss) / Gross Margin (Deficit). For the
Current Quarter, we had a gross profit of $2.4 million, or a gross
margin of approximately 3%, compared to gross profit of $1.4
million, or a gross margin of nearly 2%, for the Prior Quarter. The
$1.0 million increase in gross profit between the periods primarily
related to higher margins on slightly lower volume in the Current
Quarter compared to the Prior Quarter.
LEH Operating Fee. The LEH operating fee under the Amended
and Restated Operating Agreement was relatively flat at $0.1
million in the Current Quarter compared to $0.1 million in the
Prior Quarter. (See “Part I, Item 1. Financial Statements
– Note (9) Related-Party Transactions” for additional
disclosures related to the Amended and Restated Operating
Agreement.)
General and Administrative Expenses. General and
administrative expenses totaled $0.7 million in the Current Quarter
compared to $0.9 million in the Prior Quarter, a decrease of
approximately 30%. The decrease between the periods was primarily
due to lower legal expenses related to the GEL matter.
Depreciation and Amortization. We recorded depreciation and
amortization expenses of $0.6 million in the Current Quarter
compared to $0.5 million in the Prior Quarter, an increase of 32%.
The increase related to placement in service of a new boiler and
new petroleum storage tanks.
Other Income (Expense). Total
other income was $7.2 million in the Current Quarter compared to an
expense of $0.7 million in the Prior Quarter. Total other income in
the Current Quarter was the result of a $9.1 million gain on the
extinguishment of debt related to the GEL Settlement. Interest and
other expense totaled $1.9 million in the Current Quarter compared
to $0.8 million in the Prior Quarter. The significant increase
primarily related to the addition of a line of credit with Pilot
and secured loans with Veritex
Community Bank (“Veritex”) no longer being capitalized
in the Current Quarter compared to the Prior
Quarter.
Net Income (Loss). For the Current Quarter, we reported net
income of $8.2 million, or income of $0.74 per share, compared to a
net loss of $0.9 million, or a loss of $0.09 per share, for the
Prior Quarter. The significant increase between the periods was the
result of a gain on the extinguishment of debt related to the GEL
Settlement. Excluding the gain on
extinguishment of debt, we would have reported a net loss of $1.0
million, or a loss of $0.09 per share, for the Current
Quarter. Net loss for the Prior Quarter was primarily the
result of lower and sometimes negative margins per bbl on refined
petroleum products.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Nine Months Ended September 30, 2019 (the “Current Nine
Months”) Compared to September 30, 2018 (the “Prior
Nine Months”).
Total Revenue from Operations. For the Current Nine Months,
we had total revenue from operations of $225.9 million compared to
total revenue from operations of $256.9 million for the Prior Nine
Months, a decrease of 12%. Approximately 99% of our revenue is
derived from refinery operations while 1% is derived from tolling
and terminaling. Refinery operations revenue decreased
approximately $31.6 million in the Current Nine Months compared to
the Prior Nine Months. The decrease in refinery operations revenue
was due to lower commodity pricing per bbl on refined petroleum
products sold and slightly lower sales volume in the Current Nine
Months compared to the Prior Nine Months. For the same period,
tolling and terminaling revenue increased approximately $0.6
million, or approximately 22%, as a result of increased storage
fees under new and renewed customer agreements.
Total Cost of Goods Sold. Total cost of goods sold was
$220.3 million for the Current Nine Months compared to $249.7
million for the Prior Nine Months. The nearly 12% decrease in total
cost of goods sold in the Current Nine Months compared to the Prior
Nine Months related to lower commodity prices per bbl for crude oil
and chemicals and slightly decreased throughput
volume.
Gross Profit / Gross Margin. For the Current Nine Months,
gross profit totaled $5.6 million, or gross margin of nearly 3%,
compared to gross profit of $7.2 million, or gross margin of nearly
3%, for the Prior Nine Months. The decrease in gross profit between
the periods primarily related to lower margins on slightly less
volume in the Current Nine Months compared to the Prior Nine
Months.
LEH Operating Fee. The LEH operating fee under the Amended
and Restated Operating Agreement was relatively flat at $0.5
million in the Current Nine Months compared to the Prior Nine
Months. (See “Part I, Item 1. Financial Statements –
Note (9) Related-Party Transactions” for additional
disclosures related to the Amended and Restated Operating
Agreement.)
General and Administrative Expenses. General and
administrative expenses totaled $1.9 million in the Current Nine
Months compared to $2.3 million in the Prior Nine Months, a
decrease of 16%. The decrease between the periods was primarily due
to lower legal expenses related to the GEL matter.
Depreciation and Amortization. We recorded depreciation and
amortization expenses of $1.9 million in the Current Nine Months
compared to $1.4 million in the Prior Nine Months, an increase of
nearly 33%. The increase related to placement in service of a new
boiler and new petroleum storage tanks.
Other Income (Expense). Total
other income was $4.4 million in the Current Nine Months compared
to an expense of $2.2 million in the Prior Nine Months. Total other
income in the Current Nine Months was the result of a $9.1 million
gain on the extinguishment of debt related to the GEL
Settlement. Interest and other
expense totaled $4.7 million in the Current Nine Months compared to
$2.3 million in the Prior Quarter. The significant increase
primarily related to the addition of a line of credit with Pilot
and secured loans with Veritex no longer being capitalized in the
Current Nine Months compared to the Prior Nine
Months.
Income Tax Benefit. We recognized an income tax benefit of
$0 in the Current Nine Months compared to $0.3 million in the Prior
Nine Months. Income tax benefit in the Prior Nine Months related to
a refundable Alternative Minimum Tax credit. (See “Part I,
Item 1. Financial Statements – Note (16) Income Taxes”
for additional disclosures related to income taxes.)
Net Income (Loss). For the Current Nine Months, we reported
net income of $5.6 million, or income of $0.51 per share, compared
to net income of $0.7 million, or income of $0.07 per share, for
the Prior Nine Months. The significant increase between the periods
was the result of a gain on the extinguishment of debt related to
the GEL Settlement. Excluding the gain on the extinguishment of
debt, we would have reported a net loss of $3.5 million, or a loss
of $0.32 per share, for the Current Nine Months. The gain on the
extinguishment of debt and slightly increased tank rental revenue
offset less favorable margins per bbl and slightly lower sales
throughput volume in the Current Nine Months compared to the Prior
Nine Months.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Non-GAAP Financial Measures
To supplement our consolidated results, management uses refining
gross profit per bbl, a non-GAAP financial measure, to help
investors evaluate our core operating results and allow for greater
transparency in reviewing our overall financial, operational and
economic performance. Refining gross profit per bbl is reconciled
to GAAP-based results below. Refining gross profit per bbl should
not be considered an alternative for GAAP results. Refining gross
profit per bbl is provided to enhance an overall understanding of
our core financial performance for the applicable periods and is an
indicator that management believes is relevant and useful. Refining
gross profit per bbl 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.)
Refining Gross Profit per Bbl – For the Current
Quarter, we had a refining gross profit of $1.11 per bbl compared
to a refining gross profit of $0.29 per bbl for the Prior Quarter,
reflecting an increase of $0.82 per bbl. The significant increase
between the periods primarily related to higher margins due to
market fluctuations in the Current Quarter compared to the Prior
Quarter. (See “Glossary of Selected Energy and Financial
Terms” in this Quarterly Report for the definition of gross
margin per bbl.)
For the
Current Nine Months, we had refining gross profit of $0.71 per bbl
compared to a refining gross profit of $1.37 per bbl for the Prior
Nine Months, reflecting a decrease of $0.66 per bbl. The
significant decrease between the periods primarily related to lower
margins due to market fluctuations in the Current Nine Months
compared to the Prior Nine Months.
|
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
|
|
(in thousands
except per bbl amounts)
|
|
|
|
|
|
|
|
Refinery
operations revenue
|
$77,537
|
$94,468
|
$222,652
|
$254,245
|
|
Less:
Total cost of goods sold
|
(76,229)
|
(94,126)
|
(220,301)
|
(249,708)
|
|
|
1,308
|
342
|
2,351
|
4,537
|
|
|
|
|
|
|
|
Sales
(Bbls)
|
1,181
|
1,192
|
3,314
|
3,324
|
|
|
|
|
|
|
|
Gross
Margin per Bbl
|
$1.11
|
$0.29
|
$0.71
|
$1.37
|
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Refinery Operations Throughput and Production Data
Operational metrics
for the refinery for the periods indicated were as
follow:
|
|
Three Months
Ended September 30,
|
Nine Months
Ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calendar
Days
|
92
|
92
|
273
|
273
|
|
Refinery
downtime
|
(2)
|
(3)
|
(20)
|
(24)
|
|
Operating
Days
|
90
|
89
|
253
|
249
|
|
|
|
|
|
|
|
Total
refinery throughput (bbls)
|
1,198,102
|
1,220,259
|
3,379,266
|
3,411,193
|
|
Operating days:
|
|
|
|
|
|
bpd
|
13,312
|
13,711
|
13,357
|
13,700
|
|
Capacity
utilization rate
|
88.7%
|
91.4%
|
89.0%
|
91.3%
|
|
Calendar days:
|
|
|
|
|
|
bpd
|
13,023
|
13,264
|
12,378
|
12,495
|
|
Capacity
utilization rate
|
86.8%
|
88.4%
|
82.5%
|
83.3%
|
|
|
|
|
|
|
|
Total
refinery production (bbls)
|
1,169,745
|
1,184,348
|
3,294,914
|
3,313,682
|
|
Operating days:
|
|
|
|
|
|
bpd
|
12,997
|
13,307
|
13,023
|
13,308
|
|
Capacity
utilization rate
|
86.6%
|
88.7%
|
86.8%
|
88.7%
|
|
Calendar days:
|
|
|
|
|
|
bpd
|
12,715
|
12,873
|
12,069
|
12,138
|
|
Capacity
utilization rate
|
84.8%
|
85.8%
|
80.5%
|
80.9%
|
|
Note:
|
The
small difference between total refinery throughput (volume
processed as input) and total refinery production (volume processed
as output) represents a combination of multiple factors including
refinery fuel use, elimination of some impurities originally
present in the crude oil, loss, and other factors.
|
For the
Current Quarter, total refinery throughput bbls and total refinery
production bbls were down slightly compared to the Prior Quarter as
a result of a crude heater issue. Management plans to address the
crude heater issue during the next refinery turnaround. During the
Current Quarter, the refinery experienced 2 days of downtime
primarily related to equipment repairs. During the Prior Quarter,
the refinery experienced 3 days of downtime primarily related to
maintenance and equipment repairs.
For the
Current Nine Months compared to the Prior Nine Months, total
refinery throughput bbls and total refinery production bbls were
also down slightly as a result of the crude heater noted above.
During the Current Nine Months, the refinery experienced 20 days of
downtime primarily related to a maintenance turnaround and
equipment repairs. During the Prior Nine Months, the refinery
experienced 24 days of downtime primarily related to repair and
maintenance of the naphtha stabilizer unit and short maintenance
turnarounds scheduled in January and March of 2018.
Refined Petroleum Product Sales Summary.
See
“Part I, Item 1. Financial Statements – Note (14)
Concentration of Risk” for a discussion of refined petroleum
product sales.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Liquidity and Capital Resources
Overview.
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 quarterly net losses, inadequate working capital, and
defaults under secured loan agreements. However, management has made significant progress towards
improving operations and financial stability. Over the past
2 years, a significant portion of our cash from operations was
dedicated to reducing the outstanding
balance of the Final Arbitration Award. During the Current
Quarter, the Lazarus Parties successfully made the final payment
related to the Final Arbitration Award and the Settlement between
GEL and the Lazarus Parties became final and effective. See
“Part I, Item 1. Financial Statements – Note (1)
Organization –Going Concern” for additional disclosures
related to defaults under secured loan agreements and going
concern. See “Part I., Item 1. Financial Statements –
Note (18) Commitments and Contingencies –Final Arbitration
Award and Settlement Agreement” for additional disclosures
related to the Final Arbitration Award and the Settlement Agreement
with GEL.
Our results of operations and liquidity are highly dependent upon
the margins that we receive for our refined petroleum products.
The dollar per bbl price difference between crude oil and
condensate (input) and refined petroleum products (output), is the
most significant driver of refining margins, and they have
historically been subject to wide fluctuations. There can be no assurance that margins for refined
petroleum products will be favorable, LEH and its affiliates will
continue to fund our working capital needs in periods of working
capital deficits, or we will be able to obtain additional financing
on commercially reasonable terms or at all.
Cash Flow.
We
currently rely on revenue from operations, LEH and its affiliates
(including Jonathan Carroll), and borrowings under bank facilities
to meet our liquidity needs. Primary uses of cash include: (i)
purchase of crude oil and condensate, (ii) payment to LEH for our
direct operating expenses under the Amended and Restated Operating
Agreement, (iii) payments on long-term debt, and (iv) construction
in progress.
Our
cash flow from operations for the periods indicated was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
Beginning
cash, cash equivalents, and restricted cash
|
$1,967
|
$2,012
|
$1,665
|
$2,146
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
|
|
|
|
Adjusted
profit (loss) from operations
|
362
|
(366)
|
(778)
|
2,229
|
|
Change
in assets and current liabilities
|
408
|
400
|
(9,746)
|
(1,075)
|
|
|
|
|
|
|
|
Total
cash flow from operations
|
770
|
34
|
(10,524)
|
1,154
|
|
|
|
|
|
|
|
Cash
inflows (outflows)
|
|
|
|
|
|
Proceeds
from issuance of debt
|
-
|
-
|
12,402
|
-
|
|
Payments
on debt
|
(771)
|
224
|
(1,312)
|
(723)
|
|
Net
activity on related-party debt
|
(178)
|
472
|
(407)
|
924
|
|
Capital
expenditures
|
(964)
|
(595)
|
(1,458)
|
(1,826)
|
|
|
|
|
|
|
|
Total
cash inflows (outflows)
|
(1,557)
|
101
|
10,039
|
(1,625)
|
|
|
|
|
|
|
|
Total
change in cash flows
|
(787)
|
135
|
(485)
|
(471)
|
|
|
|
|
|
|
|
Ending
cash, cash equivalents, and restricted cash
|
$1,180
|
$2,147
|
$1,180
|
$1,675
|
For the
Current Quarter, we had cash flow from operations of $0.8 million
compared to cash flow from operations of $0.03 million for the
Prior Quarter. The approximate $0.8 million increase in cash flow
from operations between the periods related to paying out less in
cash payments toward the accrued arbitration award during the
Current Quarter than in the Prior Quarter.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
For the
Current Nine Months, we had a cash flow deficit of $10.5 million
compared to cash flow from operations of $1.2 million for the Prior
Nine Months. The $9.3 million decrease in cash flow from operations
between the periods was primarily the result of cash payments
toward the accrued arbitration award, which included a $10.0
million settlement payment to GEL. We had proceeds from the
issuance of debt of $12.4 million in the Current Nine Months
compared to $0 in the Prior Nine Months. Proceeds from the issuance
of debt, which related to a line of credit with Pilot, were used
primarily to fund the settlement payment to GEL. See “Part I,
Item 1. Note (12) Line of Credit Payable” for additional
disclosures related to debt agreement with Pilot.
Working Capital.
We had a working capital deficit of $64.9 million and $71.9 million
at September 30, 2019 and December 31, 2018, respectively.
Excluding the current portion of long-term debt, we had a working
capital deficit of $22.9 million and $30.0 at September 30, 2019 at
December 31, 2018, respectively.
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.
Crude Oil and Condensate Supply.
We have
a long-term crude supply contract in place with Pilot. In
connection with the crude supply contract, Pilot stores its crude
oil at the Nixon Facility pursuant to a terminal services
agreement. Pilot currently provides us with adequate amounts of
crude oil and condensate on favorable terms, and we expect Pilot to
continue to do so for the foreseeable future. Operation of the
Nixon refinery depends on our ability to purchase adequate amounts
of crude oil and condensate, and our ability to purchase adequate
amounts of crude oil and condensate could be adversely affected by
net losses, working capital deficits, and financial covenant
defaults in secured loan agreements. (See “Part I, Item 1. Financial Statements - Note
(19) Subsequent Event” for additional disclosures related to the
crude supply
contract.)
Capital Spending.
Since
2015, the Nixon Facility has been undergoing a capital improvement
expansion project. Capital improvements have primarily related to
construction of new petroleum storage tanks to significantly
increase petroleum storage capacity. However, smaller efficiency
improvements have been made as well. Increased petroleum storage
capacity: (i) assists with de-bottlenecking the facility, (ii)
supports increased refinery throughput up to approximately 30,000
bpd, and (iii) provides an opportunity to generate additional
tolling and terminaling revenue. When the expansion project is
complete, petroleum storage capacity at the Nixon Facility will
exceed 1.2 million bbls, an increase of more than 0.9 million
bbls.
For the
next 12 months, we expect to continue
to incur capital expenditures related to facility and land
improvements and completion of an unfinished petroleum storage
tank. Capital spending at the Nixon Facility is being funded
by working capital derived from revenue from operations and LEH and
its affiliates (including Jonathan Carroll), as well as from
long-term debt from Veritex that was secured in 2015 for expansion
of the Nixon Facility. Unused amounts under the Veritex loans are
reflected in restricted cash (current and non-current portions) on
our consolidated balance sheets. See
“Part I, Item 1. Financial Statements – Note (11)
Long-Term Debt and Accrued Interest” for additional
disclosures related to borrowings for capital
spending.
We
account for our capital expenditures in accordance with GAAP. We
also distinguish between capital expenditures that are for
maintenance and those that are for expansion. We classify a capital
expenditure as maintenance if it maintains capacity or throughput.
A classification of expansion is used if the capital expenditure is
expected to increase capacity or throughput. The distinction
between maintenance and expansion is made consistent with our
accounting policies and is generally a straightforward process.
However, in certain circumstances the distinction can be a matter
of management judgment and discretion.
Budgeting
and approval of maintenance capital expenditures is done throughout
the year on a project-by-project basis. We budget for and make
maintenance capital expenditures that are necessary to maintain
safe and efficient operations, meet customer needs and comply with
operating policies and applicable law. We may budget for and make
additional maintenance capital expenditures that we expect to
produce economic benefits such as increasing efficiency and/or
lowering future expenses. Budgeting and approval of expansion
capital expenditures are generally made periodically on a
project-by-project basis in response to specific investment
opportunities identified by our business segments.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 9/30/19
|
Contractual Obligations and Debt Agreements.
See the
following notes under “Part I, Item 1. Financial
Statements” regarding:
●
GEL. “Note (18) Commitments and
Contingencies– Final Arbitration Award and Settlement
Agreement” for disclosures related to the Final Arbitration
Award to GEL and Settlement Agreement with GEL.
●
Related-Party. “Note (9)
Related-Party Transactions” for a summary of the agreements
we have in place with related parties.
●
Long-Term Debt. “Note (11)
Long-Term Debt and Accrued Interest” for a summary of our
long-term debt.
●
Short-Term Debt. “Note (13) Line
of Credit Payable” for a summary of our short-term
debt.
●
Operating and Finance Leases.
“Note (15) Leases” for disclosures related to our
operating and finance leases.
●
Supplemental Pipeline Bonds and Abandonment
Requirements. “Note (18) Commitments and Contingencies
– Supplemental Pipeline Bonds” and “— Idle
Iron” for a discussion of supplemental pipeline bonding and
offshore pipeline and platform abandonment
requirements.
Indebtedness.
The principal balances outstanding plus accrued interest on our
debt (including related-party) for the periods indicated were as
follow:
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
First
Term Loan Due 2034 (in default)
|
$22,178
|
$22,593
|
|
Amended
Pilot Line of Credit
|
12,689
|
-
|
|
Second
Term Loan Due 2034 (in default)
|
9,197
|
9,353
|
|
Notre
Dame Debt (in default)
|
8,418
|
7,821
|
|
BDPL
Loan Agreement (in default)
|
6,014
|
5,534
|
|
March
Carroll Note (in default)
|
1,705
|
1,147
|
|
March
Ingleside Note (in default)
|
1,345
|
1,283
|
|
June
LEH Note (in default)
|
868
|
611
|
|
Capital
lease
|
-
|
41
|
|
|
$62,414
|
$48,383
|
|
|
|
|
|
Less:
Current portion of long-term debt
|
(54,249)
|
(41,904)
|
|
Less:
Unamortized debt issue costs
|
(2,317)
|
(2,006)
|
Less: Accrued interest payable and accrued interest
payable,
|
|
|
related
party
|
(5,848)
|
(4,473)
|
Principal payments on long-term debt totaled $0.8 million in the
Current Quarter compared to $0.2 million in the Prior Quarter.
Principal payments on long-term debt totaled $1.3 million in the
Current Nine Months compared to $0.7 million in the Prior Nine
Months. As of the filing date of this Quarterly Report, LE
and LRM were current on monthly payments under the First Term Loan
Due 2034 and Second Term Loan Due 2034, as well as interest
payments on the Amended Pilot Line of Credit. To date, there have
been no payments under the Notre Dame Debt and the BDPL Loan
Agreement.
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As previously disclosed, the Lazarus Parties were prohibited by GEL
from making payments to Jonathan Carroll under the Amended and
Restated Guaranty Fee Agreements (see also “Part I, Item 1.
Financial Statements – Note (18) Commitments and
Contingencies – Legal Matters – Final Arbitration Award
and Settlement Agreement”). Now that the Settlement between
GEL and the Lazarus Parties is final and effective, management has
resumed payments of the common stock component to Mr. Carroll under
the agreements. On
November 14, 2019, Mr. Carroll received 1,351,851 shares of Common
Stock, which represents payment of the common stock component of
the guaranty fees for the period May 2017 through October 2019. Mr.
Carroll will receive payment of the common stock component of the
guaranty fees on a quarterly basis going forward. Currently,
management does not intend on paying Mr. Carroll the cash portion
due to Blue Dolphin’s working capital deficits. The cash
portion of guaranty fees owed to Mr. Carroll will continue to be
accrued and added to the principal balance of the March Carroll
Note. See “Part I, Item 1. Financial Statements – Note
(9) Related-Party Transactions – Financial Agreements –
March Carroll Note” and “ – Amended and Restated
Guaranty Fee Agreements” for additional disclosures related
to payments to Jonathan Carroll.
As
described elsewhere in this Quarterly Report, Veritex notified
obligors that the Final Arbitration Award constituted an event of
default under the First Term Loan Due 2034 and Second Term Loan Due
2034. In addition to existing events of default related to the
Final Arbitration Award, at September 30, 2019, 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 did not accelerate or call due the secured loan agreements
considering the Settlement Agreement. Instead, 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 Veritex worked
with LE and LRM and was aware and party to all discussions and
arrangements with GEL surrounding the Settlement Agreement,
all amendments, and the final and effective Settlement with GEL.
In a notice to obligors dated April
30, 2019 (the "Veritex Consent'), Veritex agreed to waive certain
covenant defaults and forbear from enforcing its remedies under the
secured loan agreements subject to: (i) the agreement and
concurrence of the USDA and (ii) the replenishment of a payment
reserve account in the amount of $1.0 million as required by one of
the secured loan agreements on or before August 31, 2019. As of the
filing date of this Quarterly Report, the payment reserve account
had not been fully replenished. Any exercise by Veritex of its
rights and remedies under such secured loan agreements would have a
material adverse effect on our business operations,
including crude oil and condensate procurement and our customer
relationships; financial condition; and results of operations. In
such case, the trading price of our common stock and the value of
an investment in our common stock could significantly decrease,
which could lead to holders of our common stock losing their
investment in our common stock in its entirety.
We
adopted new ASU guidance related to leases. As a result,
disclosures previously reported as indebtedness within this
“Liquidity and Capital Resources” section as capital
leases are now excluded. Amounts are now reported as finance leases
within “Part I, Item. – Note (15) Leases.” See
“Part I, Item 1. Financial Statements – Note (3)
Significant Accounting Policies – New Pronouncements
Adopted” for information related to the new lease accounting
standard.
See
“Part I, Item 1. Financial Statements – Note (1)
Organization – Going Concern” and “–
Operating Risks”, as well as “Note (11) Long-Term Debt
and Accrued Interest” for additional disclosures related to
long-term debt financial covenant violations and events of
default.
See
“Contractual Obligations and Debt Agreements –
Related-Party” within the Liquidity and Capital Resources
section for additional disclosures with respect to related-party
indebtedness.
Off-Balance Sheet Arrangements
None.
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Critical Accounting Policies
Long-Lived Assets.
See “Part I, Item 1. Financial
Statements – Note (3) Significant Accounting Policies –
Property and Equipment”.
Revenue Recognition. See
“Part I, Item 1. Financial Statements – Note (3)
Significant Accounting Policies – Revenue
Recognition”.
Inventory. See “Part I, Item 1. Financial Statements
– Note (3) Significant Accounting Policies –
Inventory”.
Asset Retirement Obligations. See “Part I, Item 1.
Financial Statements – Note (3) Significant Accounting
Policies – Asset Retirement Obligations,”
“— Note (13) Asset Retirement Obligations,” and
“— Note (18) Commitments and Contingencies – Idle
Iron”.
Income Taxes. See “Part I, Item 1. Financial
Statements – Note (3) Significant Accounting Policies –
Income Taxes” and “– Note (16) Income
Taxes”.
Recently Adopted Accounting Guidance
See “Part I, Item 1. Financial Statements – Note (3)
Significant Accounting Policies – New Pronouncements
Adopted”.
New Pronouncements Issued, Not Yet Effective
See “Part I, Item 1. Financial Statements – Note (3)
Significant Accounting Policies – New Pronouncements Issued,
Not Yet Effective”.
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Not
applicable.
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 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 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.
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Changes in Internal Control over Financial Reporting
In connection with the adoption on January 1, 2019 of new
accounting guidance for leases, we implemented new processes and
internal controls related to our leases.
Except as described above, 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
months ended September 30, 2019 that has materially affected, or is
reasonably likely to materially affect, our internal control over
financial reporting. (See “Part I, Item 4. Controls and
Procedures – Evaluation of Disclosure Controls and
Procedures” of this Quarterly Report for a discussion related
to controls and procedures.)