Note (20)
Subsequent Events
●
Part I, Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations:
Key Relationships
– Relationship with Genesis and GEL
Results of
Operations – Non-GAAP Financial Measures
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
|
(2)
|
Basis of Presentation
|
The
accompanying unaudited consolidated financial statements, which
include Blue Dolphin and subsidiaries, have been prepared in
accordance with U.S. generally accepted accounting principles
(“GAAP”) for interim consolidated financial information
and with the instructions to Form 10-Q and Article 10 of Regulation
S-X. Accordingly, certain information and footnote disclosures
normally included in our audited financial statements have been
condensed or omitted pursuant to the SEC’s rules and
regulations. Significant intercompany transactions have been
eliminated in the consolidation. In management’s opinion, all
adjustments considered necessary for a fair presentation have been
included, disclosures are adequate, and the presented information
is not misleading.
The
consolidated balance sheet as of December 31, 2016 was derived from
the audited financial statements at that date. The accompanying
consolidated financial statements should be read in conjunction
with the consolidated financial statements and notes thereto
included in our Annual Report. Operating results for the three
months ended March 31, 2017 are not necessarily indicative of the
results that may be expected for the fiscal year ending December
31, 2017, or for any other period.
|
(3)
|
Significant Accounting Policies
|
The
summary of significant accounting policies of Blue Dolphin is
presented to assist in understanding our consolidated financial
statements. Our consolidated financial statements and accompanying
notes are representations of management who is responsible for
their integrity and objectivity. These accounting policies conform
to GAAP and have been consistently applied in the preparation of
our consolidated financial statements.
Use of Estimates
.
We have made several estimates and
assumptions related to the reporting of our consolidated assets and
liabilities and to the disclosure of contingent assets and
liabilities to prepare these consolidated financial statements in
conformity with GAAP. We believe our current estimates are
reasonable and appropriate, however, actual results could differ
from those estimated.
Cash and Cash Equivalents
.
Cash and cash equivalents
represent liquid investments with an original maturity of three
months or less. Cash balances are maintained in depository and
overnight investment accounts with financial institutions that, at
times, may exceed insured deposit limits. We monitor the financial
condition of the financial institutions and have experienced no
losses associated with these accounts. Cash and cash equivalents
were $0 at March 31, 2017 compared to cash and cash equivalents of
$1,152,628 at December 31, 2016.
Restricted Cash
.
Restricted cash (current portion)
primarily represents: (i) amounts held in our disbursement account
with Sovereign attributable to construction invoices awaiting
payment from that account, (ii) a payment reserve account held by
Sovereign as security for payments under a loan agreement, and
(iii) a construction contingency account under which Sovereign will
fund contingencies. Restricted cash, noncurrent represents funds
held in the Sovereign disbursement account for payment of future
construction related expenses to build new petroleum storage tanks.
At March 31, 2017, total restricted cash was $3,521,805, comprised
of restricted cash (current portion) totaling $2,756,713 and
restricted cash, noncurrent totaling $765,092. At December 31,
2016, total restricted cash was $4,930,140, comprised of restricted
cash (current portion) totaling $3,347,835 and restricted cash,
noncurrent totaling $1,582,305
(See “Note (11) Long-Term
Debt, Net” for additional disclosures related to our loan
agreements with Sovereign.)
Accounts Receivable and Allowance for Doubtful
Accounts
.
Accounts receivable are customer
obligations due under normal trade terms. The allowance for
doubtful accounts represents our estimate of the amount of probable
credit losses existing in our accounts receivable. We have a
limited number of customers with individually large amounts due on
any given date. Any unanticipated change in any one of these
customers’ credit worthiness or other matters affecting the
collectability of amounts due from such customers could have a
material adverse effect on our results of operations in the period
in which such changes or events occur. We regularly review all our
aged accounts receivable for collectability and establish an
allowance for individual customer balances as necessary. Allowance
for doubtful accounts totaled $0 at March 31, 2017 and December 31,
2016.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Inventory
.
The
nature of our business requires us to maintain inventory, which
primarily consists of refined petroleum products and chemicals. Our
overall inventory is valued at lower of cost or 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 product inventories declines to an
amount less than our average cost, we record a write-down of
inventory and an associated adjustment to cost of refined products
sold. (See “Note (6) Inventory” for additional
disclosures related to our inventory.)
Property and Equipment
.
Refinery and Facilities
. Additions to refinery and
facilities assets are capitalized. Expenditures for repairs and
maintenance are expensed as incurred and are included as operating
expenses under the Amended and Restated Operating Agreement.
Management expects to continue making improvements to the Nixon
Facility based on technological advances.
We record refinery and facilities at cost less any adjustments for
depreciation or impairment.
Adjustment of the asset and the
related accumulated depreciation accounts are made for the refinery
and facilities asset’s retirement and disposal, with the
resulting gain or loss included in the consolidated statements of
operations. For financial reporting purposes, depreciation of
refinery and facilities assets is computed using the straight-line
method using an estimated useful life of 25 years beginning when
the refinery and facilities assets are placed in service. We did
not record any impairment of our refinery and facilities assets for
any period presented.
Pipelines and Facilities
. We record pipelines and facilities
at cost less any adjustments for depreciation or impairment.
Depreciation is computed using the straight-line method over
estimated useful lives ranging from 10 to 22 years. In accordance
with Financial Accounting Standards Board (“FASB”) ASC
guidance on accounting for the impairment or disposal of long-lived
assets, we evaluate our pipeline and facilities assets for
impairment on a periodic basis, usually annually, and when events
or circumstances indicate that the carrying value of these assets
may not be recoverable.
Management
performed periodic impairment testing of our pipeline and
facilities assets in the fourth quarter of 2016. Upon completion of
that testing, our pipeline assets were fully impaired. All pipeline
transportation services to third-parties have ceased, existing
third-party wells along our pipeline corridor have been permanently
abandoned, and no new third-party wells are being drilled near our
pipelines. However, management believes our pipeline assets have
future value based on large-scale, third-party production facility
expansion projects near the pipelines.
Oil and Gas Properties
. We account for our oil and gas
properties using the full-cost method of accounting, whereby all
costs associated with acquisition, exploration and development of
oil and gas properties, including directly related internal costs,
are capitalized on a cost center basis. Amortization of
such costs and estimated future development costs are determined
using the unit-of-production method. Our oil and gas properties had
no production during the three months ended March 31, 2017 and
2016. All leases associated with our oil and gas properties have
expired, and our oil and gas properties were fully impaired in
2011.
Construction in Progress
. Construction in progress
expenditures, which relate to construction and refurbishment
activities at the Nixon Facility, are capitalized as incurred.
Depreciation begins once the asset is placed in service. (See
“Note (7) Property, Plant and Equipment, Net” for
additional disclosures related to our refinery and facilities
assets, oil and gas properties, pipelines and facilities assets,
and construction in progress.)
Intangibles – Other
. We have an intangible asset
consisting of the Blue Dolphin Energy Company trade name in the
amount of $303,346 on our consolidated balance sheets at March 31,
2017 and December 31, 2016. We have determined the trade name to
have an indefinite useful life. We account for other intangible
assets under FASB ASC guidance related to intangibles, goodwill,
and other. Under the guidance, we test intangible assets with
indefinite lives annually for impairment. Management performed its
regular annual impairment testing of trade name in the fourth
quarter of 2016. Upon completion of that testing, we determined
that no impairment was necessary at December 31, 2016.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Debt Issue Costs
. We have debt issue costs related to
certain refinery and facilities assets debt. Debt issue costs are
capitalized and amortized over the term of the related debt using
the straight-line method, which approximates the effective interest
method. Debt issue costs are presented net with the related debt
liability. (See “Note (11) Long-Term Debt, Net” for
additional disclosures related to debt issue
costs.)
Revenue Recognition
.
Refined Petroleum Products Revenue
. Regarding our finished
products, low-sulfur diesel is sold to customers that export to
Mexico and jet fuel is sold to LEH for resale to a government
agency. Our intermediate products, including LPG, naphtha, HOBM,
and AGO, are primarily sold in nearby markets to wholesalers and
refiners for further blending and processing. Revenue from refined
petroleum products sales is recognized when sales prices are fixed
or determinable, collectability is reasonably assured, and title
passes. Title passage occurs when refined petroleum products are
delivered in accordance with the terms of the respective sales
agreements, and customers assume the risk of loss when title is
transferred. Transportation, shipping, and handling costs incurred
are included in cost of refined products sold. Excise and other
taxes that are collected from customers and remitted to
governmental authorities are not included in revenue.
Tank Rental Revenue
. Tank rental fees are invoiced monthly
in accordance with the terms of the related lease agreement and
recognized in revenue as earned.
Easement Revenue
. Land easement revenue associated with a
Master Easement Agreement between BDPL and FLNG Land II, Inc., a
Delaware corporation (“FLNG” and the “FLNG Master
Easement Agreement”), is recognized monthly as earned and is
included in other income. In February 2017, BDPL sold approximately
15 acres of certain property owned by BDPL located in Brazoria
County Texas (the "BDPL Property") to FLIQ Common Facilities, LLC,
an affiliate of FLNG. In conjunction with the sale of real estate,
the FLNG Master Easement Agreement was terminated. We recognized a
gain on the disposal of property of $1,834,500 for the three months
ended March 31, 2017 compared to $0 for the three months ended
March 31, 2016. (See “Note (19) Commitments and Contingencies
– FLNG Easements” for further discussion related to
FLNG.)
Pipeline Transportation Revenue
. Revenue from our pipeline
operations is derived from fee-based contracts and is typically
based on transportation fees per unit of volume transported
multiplied by the volume delivered. Revenue is recognized when
volumes have been physically delivered for the customer through the
pipeline. All pipeline transportation services to third-parties
have ceased, existing third-party wells along our pipeline corridor
have been permanently abandoned, and no new third-party wells are
being drilled near our pipelines. (See “Note (4) Business
Segment Information” for further discussion related to
pipeline transportation revenue.)
Deferred Revenue
. In 2014, we recognized $850,000 in
deferred revenue related to cash collateral for supplemental
pipeline bonds. The deferred revenue was recognized on a
straight-line basis through December 31, 2018, the expected
retirement date of the associated assets. In 2015, a significant
portion of the remaining deferred revenue was recognized because of
abandoning a segment of the pipeline assets. (See “Part I,
Business – Governmental Regulation – Offshore Safety
and Environmental Oversight – Decommissioning
Requirements” in our Annual Report for a discussion related
to supplemental pipeline bonds.)
Income Taxes
. We account for income taxes under FASB ASC
guidance related to income taxes, which requires recognition of
income taxes based on amounts payable with respect to the Current
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.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
As of
each reporting date, management considers new evidence, both
positive and negative, to determine the realizability of deferred
tax assets. Management considers whether it is more likely than not
that a portion or all the deferred tax assets will be realized,
which is dependent upon the generation of future taxable income
prior to the expiration of any net operating loss
(“NOL”) carryforwards. When management determines that
it is more likely than not that a tax benefit will not be realized,
a valuation allowance is recorded to reduce deferred tax assets. A
significant piece of objective negative evidence evaluated was the
cumulative loss incurred over the three-year period ended December
31, 2016. Such objective evidence limits the ability to consider
other subjective evidence, such as our projections for future
growth. Based on this evaluation, we recorded a full valuation
allowance against the deferred tax assets as of December 31,
2016.
FASB
ASC guidance related to income taxes also prescribes a recognition
threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to
be taken in a tax return, as well as guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosures, and transition.
(See
“Note (16) Income Taxes” for further information
related to income taxes.)
Impairment or Disposal of Long-Lived Assets
. In accordance
with FASB ASC guidance on accounting for the impairment or disposal
of long-lived assets, we periodically evaluate our long-lived
assets for impairment. Additionally, we evaluate our long-lived
assets when events or circumstances indicate that the carrying
value of these assets may not be recoverable. The carrying value is
not recoverable if it exceeds the sum of the undiscounted cash
flows expected to result from the use and eventual disposition of
the asset or group of assets. If the carrying value exceeds the sum
of the undiscounted cash flows, an impairment loss equal to the
amount by which the carrying value exceeds the fair value of the
asset or group of assets is recognized. Significant management
judgment is required in the forecasting of future operating results
that are used in the preparation of projected cash flows and,
should different conditions prevail or judgments be made, material
impairment charges could be necessary.
Asset Retirement Obligations
. FASB ASC guidance related to
asset retirement obligations (“AROs”) requires that a
liability for the discounted fair value of an ARO be recorded in
the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted towards its future
value each period, and the capitalized cost is depreciated over the
useful life of the related asset. If the liability is settled for
an amount other than the recorded amount, a gain or loss is
recognized.
Management
has concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facilities assets arises
and a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
We
recorded an ARO liability related to future asset retirement costs
associated with dismantling, relocating, or disposing of our
offshore platform, pipeline systems, and related onshore
facilities, as well as for plugging and abandoning wells and
restoring land and sea beds. We developed these cost estimates for
each of our assets based upon regulatory requirements, structural
makeup, water depth, reservoir characteristics, reservoir depth,
equipment demand, current retirement procedures, and construction
and engineering consultations. Because these costs typically extend
many years into the future, estimating future costs are difficult
and require management to make judgments that are subject to future
revisions based upon numerous factors, including changing
technology, political, and regulatory environments. We review our
assumptions and estimates of future abandonment costs on an annual
basis.
(See
“Note (12) Asset Retirement Obligations” for additional
information related to our AROs.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
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.)
Treasury Stock
. We account for treasury stock under the cost
method. When treasury stock is re-issued, the net change in share
price after acquisition of the treasury stock is recognized as a
component of additional paid-in-capital in our consolidated balance
sheets. (See “Note (13) Treasury Stock” for additional
disclosures related to treasury stock.)
New Pronouncements Adopted
. The FASB issues an Accounting
Standards Update (“ASU”) to communicate changes to the
FASB ASC, including changes to non-authoritative SEC content.
Recently adopted ASUs include:
ASU 2015-11,
Inventory
(Topic 330):
Simplifying
the Measurement of Inventory
. In July 2015, FASB issued ASU
2015-11, which requires an entity to measure inventory at the lower
of cost or net realizable value. We adopted this accounting
pronouncement effective January 1, 2017. The adoption of ASU
2015-11 did not have a significant impact on our consolidated
financial statements.
New Pronouncements Issued, Not Yet Effective
. The following
are recently issued, but not yet effective, ASU’s that may
influence our consolidated financial position, results of
operations, or cash flows:
ASU 2017-04, Intangibles – Goodwill and Other (Topic 350):
Simplifying the Test for Goodwill Impairment.
In January 2017, FASB issued ASU 2017-04. This
guidance simplifies the subsequent measurement of goodwill by
eliminating Step 2 from the goodwill impairment test. For public
business entities that are SEC filers, the amendments in ASU
2017-04 are effective for the annual or any interim goodwill
impairment tests in fiscal years beginning after December 15, 2019.
ASU 2017-04 should be applied prospectively, and early adoption is
permitted for interim or annual goodwill impairment tests performed
on testing dates after January 1, 2017. We are evaluating the
impact that adoption of this guidance will have on our consolidated
balance sheets.
ASU 2016-13,
Financial Instruments —
Credit Losses (Topic 326): Measurement of Credit Losses on
Financial Instruments)
. In June
2016, FASB issued ASU 2016-13.
This
guidance updates the current impairment model to incorporate both
expected and incurred credit losses, eliminating potential
overstatements of assets and resulting in more timely recognition
of losses.
For a public business
entity, the amendments in ASU 2016-13 are effective for fiscal
years beginning after December 15, 2019, including interim periods
within those fiscal years. Early application as of the fiscal years
beginning after December 15, 2018, including interim periods within
those fiscal years, is permitted. We are evaluating the impact that
adoption of this guidance will have on our consolidated financial
statements.
ASU 2016-02,
Leases (Topic
842)
. In February 2016, FASB
issued ASU 2016-02.
This
guidance i
ncreases transparency and
comparability among organizations by recognizing lease assets and
lease liabilities on the balance sheet and disclosing key
information about leasing arrangements. For a public business
entity, the amendments in ASU 2016-02 are effective for fiscal
years beginning after December 15, 2018, including interim periods
within those fiscal years. Early application is permitted. We are
evaluating the impact that adoption of this guidance will have on
our consolidated balance sheets.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Other new pronouncements issued but not yet effective are not
expected to have a material impact on our financial position,
results of operations, or liquidity.
Reclassification
. Effective
January 1, 2017, we reclassified current and prior period amounts
associated with our Pipeline Transportation operations to Corporate
and Other.
(See “Note (4) Business Segment
Information” for disclosures related to Corporate and
Other.)
|
(4)
|
Business
Segment Information
|
Effective January 1, 2017, we began reporting a single business
segment – Refinery Operations. Business activities related to
our Refinery Operations business segment are conducted at the Nixon
Facility. Due to their small size, current and prior period amounts
associated with Pipeline Transportation operations have been
reclassified to Corporate and Other. Pipeline Transportation
operations diminished significantly as services to third-parties
ceased and third-party wells along our pipeline corridor were
permanently abandoned.
Business segment information for the
periods indicated (and as of the dates indicated), was as
follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
from operations
|
$
52,605,749
|
$
-
|
$
52,605,749
|
$
31,484,624
|
$
27,652
|
$
31,512,276
|
|
Less: cost of operations
(1)
|
(55,195,761
)
|
(430,622
)
|
(55,626,383
)
|
(34,422,853
)
|
(346,903
)
|
(34,769,756
)
|
|
Other non-interest income
(2)
|
-
|
2,216,251
|
2,216,251
|
-
|
130,665
|
130,665
|
|
Less: JMA Profit Share
(3)
|
-
|
-
|
-
|
671,092
|
-
|
671,092
|
|
EBITDA
(4)
|
$
(2,590,012
)
|
$
1,785,629
|
|
$
(2,267,137
)
|
$
(188,586
)
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation and
|
|
|
|
|
|
|
|
amortization
|
|
|
(451,025
)
|
|
|
(440,453
)
|
|
Interest
expense, net
|
|
|
(594,542
)
|
|
|
(418,809
)
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
(1,849,950
)
|
|
|
(3,314,985
)
|
|
|
|
|
|
|
|
|
|
Income
tax benefit
|
|
|
-
|
|
|
1,165,901
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
|
$
(1,849,950
)
|
|
|
$
(2,149,084
)
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
$
2,031,094
|
$
-
|
$
2,031,094
|
$
4,745,850
|
$
-
|
$
4,745,850
|
|
|
|
|
|
|
|
|
|
Identifiable
assets
|
$
73,246,878
|
$
1,068,383
|
$
74,315,261
|
$
87,970,266
|
$
7,237,943
|
$
95,208,209
|
|
(1)
|
Operation
cost within the Refinery Operations segment includes related
general and administrative expenses. Operation cost within
Corporate and Other includes general and administrative expenses
associated with corporate maintenance costs (such as accounting
fees, director fees, and legal expense), as well as expenses
associated with our pipeline assets and oil and/or gas leasehold
interests (such as accretion and impairment expenses).
|
|
(2)
|
Other
non-interest income reflects FLNG Land II, Inc.
(“FLNG”) easement revenue. (See “Note (19)
Commitments and Contingencies – FLNG Easements” for
further discussion related to FLNG.)
|
|
(3)
|
The JMA Profit Share represents the
GEL
Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement, which has
terminated. (
See “Note (19) Commitments and
Contingencies – Genesis Agreements” for further
discussion related to the Joint Marketing Agreement and the
contract-related dispute with GEL.)
|
|
(4)
|
EBITDA is a non-GAAP financial measure. See “Part I, Item 2.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Results of Operations –
Non-GAAP Financial Measures” for additional information
related to EBITDA.
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
|
(5)
|
Prepaid Expenses and Other Current Assets
|
Prepaid
expenses and other current assets as of the dates indicated
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
crude oil and condensate
|
$
1,337,252
|
$
-
|
|
Prepaid
insurance
|
263,180
|
248,853
|
|
Short-term
tax bond
|
-
|
505,000
|
|
Prepaid
exise taxes
|
-
|
292,338
|
|
|
|
|
|
|
$
1,600,432
|
$
1,046,191
|
Inventory
as of the dates indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Jet
fuel
|
$
2,401,460
|
$
964,124
|
|
HOBM
|
1,119,732
|
212,987
|
|
Crude
oil and condensate
|
410,842
|
26,123
|
|
AGO
|
197,140
|
143,362
|
|
Chemicals
|
135,678
|
182,751
|
|
Naphtha
|
122,748
|
533,580
|
|
Propane
|
18,101
|
11,318
|
|
LPG
mix
|
4,253
|
1,293
|
|
|
|
|
|
|
$
4,409,954
|
$
2,075,538
|
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
|
(7)
|
Property, Plant and Equipment, Net
|
Property,
plant and equipment, net, as of the dates indicated consisted of
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery
and facilities
|
$
51,004,382
|
$
50,814,309
|
|
Land
|
566,159
|
602,938
|
|
Other
property and equipment
|
652,795
|
652,795
|
|
|
52,223,336
|
52,070,042
|
|
|
|
|
|
Less:
Accumulated depletion, depreciation, and amortization
|
(7,136,269
)
|
(6,685,244
)
|
|
|
45,087,067
|
45,384,798
|
|
|
|
|
|
Construction
in progress
|
18,817,465
|
16,939,665
|
|
|
|
|
|
|
$
63,904,532
|
$
62,324,463
|
We
capitalize interest cost incurred on funds used to construct
property, plant, and equipment. The capitalized interest is
recorded as part of the asset to which it relates and is
depreciated over the asset’s useful life. Interest cost
capitalized was $2,526,041 and $2,108,298 at March 31, 2017 and
December 31, 2016, respectively.
|
(8)
|
Related Party Transactions
|
We are
party to several agreements with related parties. We believe these
related party transactions were consummated on terms equivalent to
those that prevail in arm's-length transactions.
Related Parties
.
LEH
. LEH, our controlling shareholder, owns approximately
81% of our Common Stock. Jonathan Carroll, Chairman of the Board,
Chief Executive Officer, and President of Blue Dolphin, is the
majority owner of LEH. We are party to an Amended and Restated
Operating Agreement, a Jet Fuel Sales Agreement, a Terminal
Services Agreement, a Loan and Security Agreement, and a Promissory
Note with LEH.
Ingleside Crude, LLC (“Ingleside”)
. Ingleside is
a related party of LEH and Jonathan Carroll. We are party to an
Amended and Restated Tank Lease Agreement and an Amended and
Restated Promissory Note with Ingleside.
Lazarus Marine Terminal I, LLC (“LMT”)
. LMT is a
related party of LEH and Jonathan Carroll. We are party to a
Tolling Agreement with LMT.
Jonathan Carroll
. Jonathan Carroll is Chairman of the Board,
Chief Executive Officer, and President of Blue Dolphin. We are
party to Guaranty Fee Agreements and an Amended and Restated
Promissory Note with Jonathan Carroll.
Operations Related Agreements
.
Amended and Restated Operating
Agreement
. LEH operates and manages all our properties
pursuant to the Amended and Restated Operating Agreement. The
Amended and Restated Operating Agreement expires: (i) April 1,
2020, (ii) upon written notice of either party to the Amended and
Restated Operating Agreement of a material breach by the other
party, or (iii) upon 90 days’ notice by the Board if the
Board determines that the Amended and Restated Operating Agreement
is not in our best interest. We reimburse LEH at cost plus five
percent (5%) for all reasonable Blue Dolphin expenses incurred
while LEH performs the services. Amounts expensed as fees to LEH
are reflected within refinery operating expenses in our
consolidated statements of operations. Fees owed to LEH under the
Amended and Restated Operating Agreement, if any, are reflected
within long-term debt, related party, net of current portion in our
consolidated balance sheets. (See “Note (20) Subsequent
Events” and “Part II, Item 5. Other Information”
for additional disclosures related to the Amended and Restated
Operating Agreement.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Jet Fuel Sales Agreement
. We sell jet fuel and other
products to LEH pursuant to a Jet Fuel Sales Agreement. LEH resells
these products to a government agency. In support of the Jet Fuel
Sales Agreement, we also lease Nixon Facility petroleum storage
tanks to LEH for the storage of the jet fuel under the Terminal
Services Agreement (as described below). The Jet Fuel Sales
Agreement terminates on the earliest to occur of: (a) a one-year
term expiring March 31, 2018 plus a 30-day carryover or (b)
delivery of a maximum quantity of jet fuel as defined therein.
Sales to LEH under the Jet Fuel Sales Agreement are reflected
within refined petroleum product sales in our consolidated
statements of operations.
Terminal Services Agreement
. Pursuant to a Terminal Services
Agreement, LEH leases petroleum storage tanks at the Nixon Facility
for the storage of Blue Dolphin purchased jet fuel under the Jet
Fuel Sales Agreement (as described above). The Terminal Services
Agreement had an initial term of 12 months expiring in April 2017.
The Terminal Services Agreement automatically renews for additional
terms of 6 months. The current expiration is October 2017. The
parties may terminate the Terminal Services Agreement upon 45
days’ written notice. Rental fees received from LEH under the
Terminal Services Agreement are reflected within tank rental
revenue in our consolidated statements of operations.
Amended and Restated Tank Lease Agreement
. Pursuant to an
Amended and Restated Tank Lease Agreement with Ingleside, we lease
petroleum storage tanks as needed to meet periodic, additional
storage needs. The Amended and Restated Tank Lease Agreement had an
initial term of 30 days with automatic 30-day renewal periods. The
parties may terminate the tank lease agreement upon 30 days’
written notice. Rental fees owed to Ingleside under the tank lease
agreement are reflected within long-term debt, related party, net
of current portion in our consolidated balance sheets. Amounts
expensed as rental fees to Ingleside under the Amended and Restated
Tank Lease Agreement are reflected within refinery operating
expenses in our consolidated statements of operations.
Tolling Agreement
. In May 2016, we entered a Tolling
Agreement with LMT to facilitate loading and unloading of our
petroleum products by barge at LMT’s dock facility in
Ingleside, Texas. The Tolling Agreement has a five-year term and
may be terminated at any time by the agreement of both parties. We
pay LMT a flat monthly reservation fee of $50,400. The monthly
reservation fee includes tolling volumes up to 84,000 gallons per
day. Tolling volumes totaling more than 210,000 gallons per quarter
are billed to us at $0.02 per gallon. Amounts expensed as tolling
fees to LMT under the Tolling Agreement are reflected in cost of
refined products sold in our consolidated statements of
operations.
Financial Agreements
.
Loan and Security Agreement
. In August 2016, BDPL entered a
loan and security agreement with LEH as evidenced by a promissory
note in the original principal amount of $4.0 million (the
“LEH Loan Agreement”). The LEH Loan Agreement matures
in August 2018, and accrues interest at rate of 16.00%. Under the
LEH Loan Agreement, BDPL will make payments to LEH of $500,000 per
year. A final balloon payment is due at maturity.
The
proceeds of the LEH Loan Agreement were used for working capital.
There are no financial maintenance covenants associated with the
LEH Loan Agreement. The LEH Loan Agreement is secured by the BDPL
Property. Outstanding principal and interest less associated debt
issue costs owed to LEH under the LEH Loan Agreement are reflected
in long-term debt, related party, current portion and long-term
debt, related party, net of current portion in our consolidated
balance sheets.
Promissory Notes
. We have the following promissory notes
with LEH, Ingleside and Jonathan Carroll:
●
LEH Note
–Blue Dolphin entered a
promissory note with LEH in the original principal amount of
$440,815 (the “LEH Note”). The LEH Note accrues
interest, compounded annually, at a rate of 8.00%. The principal
amount and any accrued but unpaid interest are due and payable in
January 2019. Under the LEH Note, prepayment, in whole or in part,
is permissible at any time and from time to time, without premium
or penalty. Outstanding principal and interest owed to LEH under
the LEH Note are reflected in long-term debt, related party, net of
current portion in our consolidated balance sheets. At March 31,
2017 and December 31, 2016, the outstanding principal and interest
on the LEH Note was $440,815 and $0, respectively. (See “Note
(20) Subsequent Events” and “Part II, Item 5. Other
Information” for additional disclosures related to the LEH
Note.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
●
Amended and Restated Ingleside Note
– A promissory note between Blue Dolphin and Ingleside in the
original principal amount of $679,385 was amended and restated (the
“Amended and Restated Ingleside Note”) to increase the
principal amount and extend the maturity date to January 2019. The
Amended and Restated Ingleside Note accrues interest, compounded
annually, at a rate of 8.00%. Under the Amended and Restated
Ingleside Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty.
Outstanding principal and interest owed to Ingleside under the
Amended and Restated Ingleside Note are reflected in long-term
debt, related party, net of current portion in our consolidated
balance sheets. At March 31, 2017 and December 31, 2016, the
outstanding principal and interest on the Ingleside Note was
$1,195,723 and $722,278, respectively. (See “Note (20)
Subsequent Events” and “Part II, Item 5. Other
Information” for additional disclosures related to the
Amended and Restated Ingleside Note.)
●
Amended and Restated Carroll Note
– A promissory note between Blue Dolphin and Jonathan Carroll
in the original principal amount of $422,374 was amended and
restated (the “Amended and Restated Carroll Note”) to
increase the principal amount, revise the payment terms to reflect
payment in cash and shares of Blue Dolphin Common Stock, and extend
the maturity date to January 2019. The Amended and Restated Carroll
Note accrues interest, compounded annually, at a rate of 8.00%.
Under the Amended and Restated Carroll Note, prepayment, in whole
or in part, is permissible at any time and from time to time,
without premium or penalty. Outstanding principal and interest owed
to Jonathan Carroll under the Amended and Restated Carroll Note are
reflected in long-term debt, related party, net of current portion
in our consolidated balance sheets. At March 31, 2017 and December
31, 2016, the outstanding principal and interest on the Amended and
Restated Carroll Note was $775,442 and $592,412, respectively. (See
“Note (20) Subsequent Events” and “Part II, Item
5. Other Information” for additional disclosures related to
the Amended and Restated Carroll Note.)
Guaranty Fee Agreements
. Pursuant to Guaranty Fee
Agreements, Jonathan Carroll receives fees for providing his
personal guarantee on certain of our long-term debt. Jonathan
Carroll was required to guarantee repayment of funds borrowed and
interest accrued under certain loan agreements. Amounts owed to
Jonathan Carroll under Guaranty Fee Agreements are reflected within
long-term debt, related party, net of current portion in our
consolidated balance sheets. Amounts expensed related to Guarantee
Fee Agreements are reflected within interest and other expense in
our consolidated statements of operations. (See “Note (11)
Long-Term Debt, Net” and “Note (20) Subsequent
Events” for further discussion related to guaranty fee
agreements.)
Financial Statements Impact
.
Consolidated Balance Sheets
. At March 31, 2017 and December
31, 2016, accounts receivable, related party from LEH totaled $0
and $1,161,589. Accounts payable, related party to LMT associated
with the Tolling Agreement was $520,800 and $369,600 at March 31,
2017 and December 31, 2016, respectively. Long-term debt, related
party associated with the LEH Loan Agreement, LEH Note, Ingleside
Note, and Carroll Note as of the dates indicated was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
4,440,815
|
$
4,000,000
|
|
Ingleside
|
1,195,723
|
722,278
|
|
Jonathan
Carroll
|
775,442
|
592,412
|
|
|
|
|
|
|
6,411,980
|
5,314,690
|
|
|
|
|
|
Less:
Long-term debt, related party,
|
|
|
|
current
portion
|
(500,000
)
|
(500,000
)
|
|
|
|
|
|
|
$
5,911,980
|
$
4,814,690
|
Accrued
interest associated with the LEH Loan Agreement was $403,556 and
$243,556 at March 31, 2017 and December 31, 2016, respectively.
There was no accrued interest associated with the LEH Note, the
Amended and Restated Ingleside Note, and the Amended and Restated
Carroll Note.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Consolidated Statements of Operations
. Related party revenue
from LEH associated with: (i) jet fuel sales under the Jet Fuel
Sales Agreement totaled $18,769,063 and $0 for the three months
ended March 31, 2017 and 2016 and (ii) the storage of jet fuel
under the Terminal Services Agreement totaled $375,000 and $0 for
the three months ended March 31, 2017 and 2016.
Related
party cost of goods sold associated with the Tolling Agreement with
LMT totaled $151,200 and $0 for the three months ended March 31,
2017 and 2016. Related party refinery operating expenses associated
with the Amended and Restated Operating Agreement with LEH and the
Amended and Restated Tank Lease Agreement with Ingleside for the
periods indicated were as follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LEH
|
$
2,813,103
|
$
2.80
|
$
3,162,017
|
$
2.67
|
|
Ingleside
|
-
|
-
|
274,998
|
$
0.23
|
|
|
|
|
|
|
|
|
$
2,813,103
|
$
2.80
|
$
3,437,015
|
$
2.90
|
Interest
expense associated with the LEH Loan Agreement and Guaranty Fee
Agreements for the periods indicated was as follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
LEH
|
$
207,294
|
$
-
|
|
Jonathan
Carroll
|
167,825
|
176,388
|
|
|
|
|
|
|
$
375,119
|
$
176,388
|
Our
notes payable consist of a short-term note for financing costs, as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
note for financing costs
|
$
89,660
|
$
-
|
|
|
|
|
|
|
$
89,660
|
$
-
|
Short-Term Note for Financing Services
. In March 2017, LE
entered a short-term promissory note with Baker Petrolite LLC (the
“Baker Petrolite Note”) in the amount of $136,969 for
the purchase of chemicals. The Baker Petrolite Note, which is
unsecured, matures in September 2017, has a current monthly payment
of principal in the amount of $10,000, and accrues interest at a
rate of 10.00%.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
|
(10)
|
Accrued Expenses and Other Current Liabilities
|
Accrued
expenses and other current liabilities as of the dates indicated
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unearned
revenue
|
$
1,336,302
|
$
408,770
|
|
Customer
deposits
|
450,000
|
450,000
|
|
Board
of director fees payable
|
168,929
|
136,429
|
|
Other
payable
|
113,123
|
189,719
|
|
Insurance
|
88,206
|
67,783
|
|
Excise
and income taxes payable
|
50,957
|
24,187
|
|
Property
taxes
|
36,236
|
4,694
|
|
|
|
|
|
|
$
2,243,753
|
$
1,281,582
|
Long-term
debt, net, which includes related-party, represents the outstanding
principal and interest of our long-term debt less associated debt
issue costs. Long-term debt, net as of the dates indicated
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Term Loan Due 2034
|
$
23,745,152
|
$
23,924,607
|
|
Second
Term Loan Due 2034
|
9,663,450
|
9,729,853
|
|
LEH
Loan Agreement
|
4,000,000
|
4,000,000
|
|
Amended
and Restated Ingleside Note
|
1,195,723
|
722,278
|
|
Notre
Dame Debt
|
1,300,000
|
1,300,000
|
|
Amended
and Restated Carroll Note
|
775,442
|
592,412
|
|
LEH
Note
|
440,815
|
-
|
|
Term
Loan Due 2017
|
-
|
184,994
|
|
Capital
Leases
|
93,153
|
135,879
|
|
|
$
41,213,735
|
$
40,590,023
|
|
|
|
|
|
Less:
Current portion of long-term debt, net
|
(33,070,879
)
|
(32,212,336
)
|
|
|
|
|
|
Less:
Unamortized debt issue costs
|
(2,230,876
)
|
(2,262,997
)
|
|
|
|
|
|
|
$
5,911,980
|
$
6,114,690
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Debt
issue costs, which relate to secured loan agreements with
Sovereign, as of the dates indicated consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Term Loan Due 2034
|
$
1,673,545
|
$
1,673,545
|
|
Second
Term Loan Due 2034
|
767,673
|
767,673
|
|
|
|
|
|
Less:
Accumulated amortization
|
(210,342
)
|
(178,221
)
|
|
|
|
|
|
|
$
2,230,876
|
$
2,262,997
|
Amortization
expense associated with our long-term debt, net, which is included
in interest expense, was $32,121 and $31,869 for the three months
ended March 31, 2017 and 2016, respectively.
Accrued
interest associated with our long-term debt, net is reflected as
interest payable, current portion and long-term interest payable,
net of current portion in our consolidated balance sheets and
includes related party interest. Accrued interest as of the dates
indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Notre
Dame Debt
|
$
1,742,673
|
$
1,691,383
|
|
LEH
Loan Agreement
|
403,556
|
243,556
|
|
Second
Term Loan Due 2034
|
45,726
|
44,984
|
|
First
Term Loan Due 2034
|
28,090
|
33,866
|
|
Capital
Leases
|
795
|
1,165
|
|
Term
Loan Due 2017
|
-
|
185
|
|
|
|
|
|
|
2,220,840
|
2,015,139
|
|
|
|
|
|
Less:
Interest payable, current portion
|
(2,220,840
)
|
(323,756
)
|
|
|
|
|
|
|
$
-
|
$
1,691,383
|
Related Party
. See “Note (8) Related Party
Transactions” for additional disclosures with respect to
related party long-term debt associated with the LEH Loan
Agreement, the LEH Note, the Amended and Restated Ingleside Note,
and the Amended and Restated Carroll Note.
First Term Loan Due 2034
. In 2015, LE entered a loan
agreement and related security agreement
with Sovereign as administrative
agent and lender,
providing
for a term loan in the principal amount of $25.0 million
(the “First Term Loan Due 2034”). The First Term Loan
Due 2034 matures in June 2034, has a current monthly payment of
principal and interest of $191,902, and accrues interest at a rate
based on the Wall Street Journal Prime Rate plus 2.75%. Pursuant to
a construction rider in the First Term Loan Due 2034, proceeds
available for use were placed in a disbursement account whereby
Sovereign makes payments for construction related expenses. Amounts
held in the disbursement account are reflected as restricted cash
(current portion) and restricted cash, noncurrent in our
consolidated balance sheets.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
At
March 31, 2017, LE was in violation of the debt service coverage
ratio, the current ratio, and debt to net worth ratio financial
covenants related to the First Term Loan Due 2034. Consequently,
Sovereign could declare the amounts owed under the First Term Loan
Due 2034 immediately due and payable, exercise its rights with
respect to collateral securing LE’s obligations under the
loan agreement, and/or exercise any other rights and remedies
available. Sovereign waived the financial covenant defaults as of
March 31, 2017. However, the debt associated with the loan was
classified within the current portion of long-term debt on our
consolidated balance sheet at March 31, 2017 due to the uncertainty
of our ability to meet the financial covenants in the future. There
can be no assurance that Sovereign will provide future waivers,
which may have an adverse impact on our financial position and
results of operations. (See “Note (1) Organization –
Operating Risks-Going Concern” and “Note (20)
Subsequent Events” for additional disclosures related to the
First Term Loan Due 2034 and financial covenant
violations.)
As a
condition of the First Term Loan Due 2034, Jonathan Carroll was
required to guarantee r
epayment
of funds borrowed and
interest accrued under the loan. For his personal guarantee, LE
entered a Guaranty Fee Agreement with Jonathan Carroll whereby he
receives a fee equal to 2.00% per annum, paid monthly, of the
outstanding principal balance owed under the First Term Loan Due
2034.
For the three months ended March
31, 2017 and 2016, guaranty fees related to the First Term Loan Due
2034 totaled $118,991 and $122,633, respectively. Guaranty fees are
recognized monthly as incurred and are included in interest and
other expense in our consolidated statements of operations.
LEH, LRM and Blue Dolphin also guaranteed the First Term Loan Due
2034. (See “Note (8) Related Party Transactions” for
additional disclosures related to LEH and Jonathan Carroll; see
“Note (20) Subsequent Events” for further discussion
related to guaranty fee agreements.)
A
portion of the proceeds of the First Term Loan Due 2034 were used
to refinance approximately $8.5 million of debt owed under a
previous debt facility with American First National Bank. Remaining
proceeds are being used primarily to construct new petroleum
storage tanks at the Nixon Facility. The First Term Loan Due 2034
is secured by: (i) a first lien on all Nixon Facility business
assets (excluding accounts receivable and inventory), (ii)
assignment of all Nixon Facility contracts, permits, and licenses,
(iii) absolute assignment of Nixon Facility rents and leases,
including tank rental income, (iv) a $1.0 million payment reserve
account held by Sovereign, and (v) a pledge of $5.0 million of a
life insurance policy on Jonathan Carroll. The First Term Loan Due
2034 contains representations and warranties, affirmative,
restrictive, and financial covenants, as well as events of default
which are customary for bank facilities of this type.
Second Term Loan Due 2034
. In 2015, LRM entered a loan
agreement and related security agreement with Sovereign as
administrative agent and lender, providing for a term loan in the
principal amount of $10.0 million (the “Second Term Loan Due
2034”). The Second Term Loan Due 2034 matures in December
2034, has a current monthly payment of principal and interest of
$74,111, and accrues interest at a rate based on the Wall Street
Journal Prime Rate plus 2.75%. Pursuant to a construction rider in
the Second Term Loan Due 2034, proceeds available for use were
placed in a disbursement account whereby Sovereign makes payments
for construction related expenses. Amounts held in the disbursement
account are reflected as restricted cash (current portion) and
restricted cash, noncurrent in our consolidated balance
sheets.
At
March 31, 2017, LRM was in violation of the debt service coverage
ratio, the current ratio, and the debt to net worth ratio financial
covenants related to the Second Term Loan Due 2034. Consequently,
Sovereign could declare the amounts owed under the Second Term Loan
Due 2034 immediately due and payable, exercise its rights with
respect to collateral securing LRM’s obligations under the
loan agreement, and/or exercise any other rights and remedies
available. Sovereign waived the financial covenant defaults as of
March 31, 2017. However, the debt associated with the loan was
classified within the current portion of long-term debt on our
consolidated balance sheet at March 31, 2017 due to the uncertainty
of our ability to meet the financial covenants in the future. There
can be no assurance that Sovereign will provide future waivers,
which may have an adverse impact on our financial position and
results of operations. (See “Note (1) Organization –
Operating Risks-Going Concern” and “Note (20)
Subsequent Events” for additional disclosures related to the
Second Term Loan Due 2034 and financial covenant
violations.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
As a
condition of the Second Term Loan Due 2034, Jonathan Carroll was
required to guarantee repayment of funds borrowed and interest
accrued under the loan. For his personal guarantee, LRM entered a
Guaranty Fee Agreement with Jonathan Carroll whereby he receives a
fee equal to 2.00% per annum, paid monthly, of the outstanding
principal balance owed under the Second Term Loan Due 2034. For the
three months ended March 31, 2017 and 2016, guaranty fees related
to the Second Term Loan Due 2034 totaled $48,423 and $49,747,
respectively. Guaranty fees are recognized monthly as incurred and
are included in interest and other expense in our consolidated
statements of operations. LEH, LE and Blue Dolphin also guaranteed
the Second Term Loan Due 2034. (See “Note (8) Related Party
Transactions” for additional disclosures related to LEH and
Jonathan Carroll; see “Note (20) Subsequent Events” for
further discussion related to guaranty fee
agreements.)
A
portion of the proceeds of the Second Term Loan Due 2034 were used
to refinance a previous bridge loan from Sovereign in the amount of
$3.0 million. Remaining proceeds are being used primarily to
construct additional new petroleum storage tanks at the Nixon
Facility. The Second Term Loan Due 2034 is secured by: (i) a second
priority lien on the rights of LE in the Nixon Facility and the
other collateral of LE pursuant to a security agreement; (ii) a
first priority lien on the real property interests of LRM; (iii) a
first priority lien on all of LRM’s fixtures, furniture,
machinery and equipment; (iv) a first priority lien on all of
LRM’s contractual rights, general intangibles and
instruments, except with respect to LRM’s rights in its
leases of certain specified tanks, with respect to which Sovereign
has a second priority lien in such leases subordinate to a prior
lien granted by LRM to Sovereign to secure obligations of LRM under
the Term Loan Due 2017; and (v) all other collateral as described
in the security documents. The Second Term Loan Due 2034 contains
representations and warranties, affirmative, restrictive, and
financial covenants, as well as events of default which are
customary for bank facilities of this type.
Notre Dame Debt
. LE entered a loan with Notre Dame
Investors, Inc. as evidenced by a promissory note in the original
principal amount of $8.0 million, which is currently held by John
Kissick (the “Notre Dame Debt”). The Notre Dame Debt
matures in January 2018, and accrues interest at a rate of
16.00%.
The
Notre Dame Debt is secured by a Deed of Trust, Security Agreement
and Financing Statements (the “Subordinated Deed of
Trust”), which encumbers the Nixon Facility and general
assets of LE. There are no financial maintenance
covenants associated with the Notre Dame Debt. Pursuant to a
Subordination Agreement dated June 2015, the holder of the Notre
Dame Debt agreed to subordinate any security interest and liens on
the Nixon Facility, as well as its right to payments, in favor of
Sovereign as holder of the First Term Loan Due 2034.
Term Loan Due 2017
. LRM entered a Loan and Security
Agreement with Sovereign in 2014, for a term loan facility in the
principal amount of $2.0 million (the “Term Loan Due
2017”). The Term Loan Due 2017 was amended in March 2015,
pursuant to a Loan Modification Agreement (the “March Loan
Modification Agreement”). Under the March Loan Modification
Agreement, the interest rate was modified to be the greater of the
Wall Street Journal Prime Rate plus 2.75% or 6.00%, and the due
date was extended to March 2017. Pursuant to the March Loan
Modification Agreement, the Term Loan Due 2017 had a monthly
principal payment of $61,665 plus interest. The Term Loan Due 2017
was paid off in March 2017.
As a
condition of the Term Loan Due 2017, Jonathan Carroll was required
to guarantee r
epayment
of funds borrowed and
interest accrued under the loan. For his personal guarantee, LRM
entered a Guaranty Fee Agreement with Jonathan Carroll whereby he
received a fee equal to 2.00% per annum, paid monthly, of the
outstanding principal balance owed under the Term Loan Due 2017.
For the three months ended March 31,
2017 and 2016, guaranty fees related to the Term Loan Due 2017
totaled $411 and $4,008, respectively. Guaranty fees are recognized
monthly as incurred and are included in interest and other expense
in our consolidated statements of operations. (See “Note (20)
Subsequent Events” for further discussion related to guaranty
fee agreements.)
Capital Leases
. LRM entered a 36-month build-to-suit capital
lease in August 2014 for the purchase of new boiler equipment for
the Nixon Facility. The equipment, which was delivered in December
2014, was added to construction in progress. Once placed in
service, the equipment will be reclassified to refinery and
facilities and depreciation will begin. The capital lease, which
requires a quarterly payment in the amount of $44,258, is
guaranteed by Blue Dolphin.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
A
summary of equipment held under long-term capital leases as of the
dates indicated follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Boiler
equipment
|
$
538,598
|
$
538,598
|
|
Less:
accumulated depreciation
|
-
|
-
|
|
|
|
|
|
|
$
538,598
|
$
538,598
|
|
(12)
|
Asset Retirement Obligations
|
Refinery and Facilities
. Management has concluded that there
is no legal or contractual obligation to dismantle or remove the
refinery and facilities assets. Management believes that the
refinery and facilities assets have indeterminate lives under FASB
ASC guidance for estimating AROs because dates or ranges of dates
upon which we would retire these assets cannot reasonably be
estimated at this time. When a legal or contractual obligation to
dismantle or remove the refinery and facilities assets arises and a
date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
Pipelines and Facilities and Oil and Gas Properties
. We have
AROs associated with the dismantlement and abandonment in place of
our pipelines and facilities assets, as well as the plugging and
abandonment of our oil and gas properties. We recorded a discounted
liability for the fair value of an ARO with a corresponding
increase to the carrying value of the related long-lived asset at
the time the asset was installed or placed in service. We
depreciate the amount added to property and equipment and recognize
accretion expense in connection with the discounted liability over
the remaining life of the asset. Plugging and abandonment costs are
recorded during the period incurred or as information becomes
available to substantiate actual and/or probable
costs.
Changes
to our ARO liability for the periods indicated were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
retirement obligations, at the beginning of the period
|
$
2,027,639
|
$
1,985,864
|
|
Liabilities
settled
|
-
|
(70,969
)
|
|
Accretion
expense
|
71,844
|
112,744
|
|
|
2,099,483
|
2,027,639
|
|
Less:
asset retirement obligations, current portion
|
(17,510
)
|
(17,510
)
|
|
|
|
|
|
Long-term
asset retirement obligations, at the end of the period
|
$
2,081,973
|
$
2,010,129
|
Liabilities
settled represents amounts paid for plugging and abandonment costs
against the asset’s ARO liability. At March 31, 2017 and
December 31, 2016, we recognized $0 and $70,969, respectively, in
liabilities settled. Abandonment expense represents amounts paid
for plugging and abandonment costs that exceed the asset’s
ARO liability. For the three months ended March 31, 2017 and 2016,
we recognized $0 in abandonment expense.
At
March 31, 2017 and December 31, 2016, we had 150,000 shares of
treasury stock.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
|
(14)
|
Concentration of Risk
|
Bank Accounts
. Financial instruments that potentially
subject us to concentrations of risk consist primarily of cash,
trade receivables and payables. We maintain our cash balances at
financial institutions located in Houston, Texas. In the U.S., the
Federal Deposit Insurance Corporation (the “FDIC”)
insures certain financial products up to a maximum of $250,000 per
depositor. At March 31, 2017 and December 31, 2016, we had cash
balances (including restricted cash) of more than the FDIC
insurance limit per depositor in the amount of $3,028,945 and
$5,372,689, respectively.
Key Supplier
.
We
purchased light crude oil and condensate for the Nixon Facility
from GEL pursuant to the Crude Supply Agreement. GEL materially
breached the Crude Supply Agreement in April 2016 by refusing to
deliver our operational requirements for crude oil for an extended
period. Consequently, we ceased purchases of crude oil and
condensate from GEL under the Crude Supply Agreement in November
2016. The Crude Supply Agreement has terminated. As previously
disclosed, we are involved in an on-going dispute with GEL related
to the Crude Supply Agreement. Arbitration proceedings related to
the dispute with GEL are currently in progress. We are unable to
predict the outcome of these proceedings or their ultimate impact,
if any, on our business, financial condition, or results of
operations. (See “Part I, Item 1A. Risk Factors” in our
Annual Report, as well as “Part I, Item 1 Financial
Statements – Note (19) Commitments and Contingencies –
Genesis Agreements” and “Legal Matters” in this
Quarterly Report for disclosures related to the Crude Supply
Agreement and the current contract-related dispute with
GEL.)
We
currently have in place a month-to-month evergreen crude supply
contract with a major integrated oil and gas company. We believe
that adequate supplies of crude oil and condensate for the Nixon
Facility are and will continue to be available to us from our new
supplier. We are working to put a long-term crude supply agreement
in place, however, our ability to purchase crude oil and condensate
is dependent on our liquidity and access to capital, which have
been adversely affected by net losses, working capital deficits,
the contract-related dispute with GEL, and financial covenant
defaults in secured loan agreements.
Significant Customers
. We routinely assess the financial
strength of our customers and have not experienced significant
write-downs in our accounts receivable balances. Therefore, we
believe that our accounts receivable credit risk exposure is
limited.
For the
three months ended March 31, 2017, we had 3 customers that
accounted for approximately 82% of our refined petroleum product
sales. At March 31, 2017, these 3 customers represented
approximately $0 million in accounts receivable. For the three
months ended March 31, 2016, we had 5 customers that accounted for
approximately 75% of our refined petroleum products sales. These 5
customers represented approximately $2.3 million in accounts
receivable at March 31, 2016.
For the
three months ended March 31, 2017, LEH, a related party, was 1 of
our 3 significant customers. LEH accounted for approximately 36% of
our refined petroleum product sales for the three months ended
March 31, 2017. LEH, which purchases our jet fuel and resells the
jet fuel to a government agency, represented approximately $0
million in accounts receivable at March 31, 2017. LEH was not a
significant customer for the three months ended March 31, 2016.
(See “Note (8) Related Party Transactions” for
additional disclosures related to our sale of jet fuel to LEH under
the Jet Fuel Sales Agreement and the associated storage of
LEH’s purchased jet fuel under the Terminal Services
Agreement.)
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Refined Petroleum Product Sales
. Our refined petroleum
products are primarily sold in the U.S. However, with the opening
of the Mexican diesel market to private companies, we began
exporting low-sulfur diesel to Mexico during the second quarter of
2016. Total refined petroleum product sales by distillation (from
light to heavy) for the periods indicated consisted of the
following:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
LPG
mix
|
$
120,542
|
0.2
%
|
$
250,547
|
0.8
%
|
|
Naphtha
|
13,762,944
|
26.5
%
|
9,025,521
|
28.9
%
|
|
Jet
fuel
|
15,399,994
|
29.7
%
|
8,506,313
|
27.3
%
|
|
HOBM
|
10,685,740
|
20.6
%
|
3,163,495
|
10.1
%
|
|
Reduced
Crude
|
-
|
0.0
%
|
3,245,807
|
10.4
%
|
|
AGO
|
11,932,818
|
23.0
%
|
7,001,454
|
22.5
%
|
|
|
|
|
|
|
|
|
$
51,902,038
|
100.0
%
|
$
31,193,137
|
100.0
%
|
Our
company headquarters is in downtown Houston, Texas. We lease 13,878
square feet of office space, 7,389 square feet of which is used and
paid for by LEH. The office lease has a 10-year term that expires
in September 2017. The lease included a free rent period, has
escalating rent payment provisions, and requires payment of a
portion of operating expenses. Rent expense is recognized on a
straight-line basis. For the three months ended March 31, 2017 and
2016, rent expense totaled
$31,081
and $29,857,
respectively.
Income Tax Benefit
. For the three months ended March 31,
2017 and 2016, we recognized an income tax benefit of $0 and
$1,165,901, respectively.
Deferred Income Taxes
. Deferred income tax balances reflect
the effects of temporary differences between the carrying amounts
of assets and liabilities and their tax basis, as well as from NOL
carryforwards. We state those balances at the enacted tax rates we
expect will be in effect when taxes are paid. NOL carryforwards and
deferred tax assets represent amounts available to reduce future
taxable income.
NOL Carryforwards
. Under Section 382 of the Internal Revenue
Code of 1986, as amended (“IRC Section 382”), a
corporation that undergoes an “ownership change” is
subject to limitations on its use of pre-change NOL carryforwards
to offset future taxable income. Within the meaning of IRC Section
382, an “ownership change” occurs when the aggregate
stock ownership of certain stockholders (generally 5% shareholders,
applying certain look-through rules) increases by more than 50
percentage points over such stockholders' lowest percentage
ownership during the testing period (generally three years). For
income tax purposes, we experienced ownership changes in 2005, in
connection with a series of private placements, and in 2012, as a
result of a reverse acquisition, that limit the use of pre-change
NOL carryforwards to offset future taxable income. In general, the
annual use limitation equals the aggregate value of common stock at
the time of the ownership change multiplied by a specified
tax-exempt interest rate. The 2012 ownership change will subject
approximately $16.3 million in NOL carryforwards that were
generated prior to the ownership change to an annual use limitation
of $638,196 per year. Unused portions of the annual use limitation
amount may be used in subsequent years. As a result of the annual
use limitation, approximately $6.7 million in NOL carryforwards
that were generated prior to the 2012 ownership change will expire
unused. NOL carryforwards that were generated after the 2012
ownership change are not subject to an annual use limitation under
IRC Section 382 and may be used for a period of 20 years in
addition to available amounts of NOL carryforwards generated prior
to the ownership change.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
NOL
carryforwards that remained available for future use for the
periods indicated were as follow (amounts shown are net of NOLs
that will expire unused because of the IRC Section 382
limitation):
|
|
Net Operating Loss Carryforward
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2015
|
$
9,614,449
|
$
9,616,941
|
$
19,231,390
|
|
|
|
|
|
|
Net
operating losses
|
-
|
13,945,128
|
13,945,128
|
|
|
|
|
|
|
Balance
at December 31, 2016
|
$
9,614,449
|
$
23,562,069
|
$
33,176,518
|
|
|
|
|
|
|
Net
operating losses
|
-
|
2,816,718
|
2,816,718
|
|
|
|
|
|
|
Balance
at March 31, 2017
|
$
9,614,449
|
$
26,378,787
|
$
35,993,236
|
Deferred Tax Assets and Liabilities
. At March 31, 2017 and
December 31, 2016, we had $0 of net deferred tax assets available
for future use. Significant components of deferred tax assets and
liabilities as of the dates indicated were as follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
tax assets:
|
|
|
|
Net
operating loss and capital loss carryforwards
|
$
14,508,022
|
$
13,550,338
|
|
Start-up
costs (Nixon Facility)
|
1,339,029
|
1,373,363
|
|
Asset
retirement obligations liability/deferred revenue
|
738,633
|
717,751
|
|
AMT
credit and other
|
237,818
|
266,522
|
|
Total
deferred tax assets
|
16,823,502
|
15,907,974
|
|
|
|
|
|
Deferred
tax liabilities:
|
|
|
|
Basis
differences in property and equipment
|
(6,182,489
)
|
(5,895,943
)
|
|
Total
deferred tax liabilities
|
(6,182,489
)
|
(5,895,943
)
|
|
|
|
|
|
|
10,641,013
|
10,012,031
|
|
|
|
|
|
Valuation
allowance
|
(10,641,013
)
|
(10,012,031
)
|
|
|
|
|
|
Deferred
tax assets, net
|
$
-
|
$
-
|
Valuation Allowance
. As of each reporting date, management
considers new evidence, both positive and negative, to determine
the realizability of deferred tax assets. Management considers
whether it is more likely than not that some portion or all the
deferred tax assets will be realized, which is dependent upon the
generation of future taxable income prior to the expiration of any
NOL carryforwards. At March 31, 2017 and December 31, 2016,
management determined that cumulative losses incurred over the
prior three-year period provided significant objective evidence
that limited the ability to consider other subjective evidence,
such as projections for future growth. Based on this evaluation, we
recorded a full valuation allowance against the deferred tax assets
as of March 31, 2017 and December 31, 2016.
Uncertain Tax Positions
. We adopted the provisions of the
FASB ASC guidance on accounting for uncertainty in income taxes.
The guidance clarifies the accounting for uncertainty in income
taxes recognized in an enterprise’s financial statements. The
guidance also prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement
of a tax position taken or expected to be taken in a tax return.
The standard also provides guidance on de-recognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
As part
of this guidance, we record income tax related interest and
penalties, if applicable, as a component of the provision for
income tax benefit (expense). However, there were no amounts
recognized relating to interest and penalties in the consolidated
statements of operations for the three months ended March 31, 2017
and 2016. Our federal income tax returns are subject to examination
by the Internal Revenue Service for tax years ending December 31,
2013, or after and by the state of Texas for tax years ending
December 31, 2012, or after. We believe there are no uncertain tax
positions for both federal and state income taxes.
A
reconciliation between basic and diluted income per share for the
periods indicated was as follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
$
(1,849,950
)
|
$
(2,149,084
)
|
|
|
|
|
|
Basic
and diluted income per share
|
$
(0.18
)
|
$
(0.21
)
|
|
|
|
|
|
Basic and Diluted
|
|
|
|
Weighted
average number of shares of
|
|
|
|
common
stock outstanding and potential
|
|
|
|
dilutive
shares of common stock
|
10,474,714
|
10,457,794
|
Diluted
EPS is computed by dividing net income available to common
stockholders by the weighted average number of shares of common
stock outstanding. Diluted EPS for the three months ended March 31,
2017 and 2016 was the same as basic EPS as there were no stock
options or other dilutive instruments outstanding.
|
(18)
|
Inventory Risk Management
|
Management
periodically determines whether to maintain, increase, or decrease
inventory levels based on various factors, including the crude
pricing market in the U.S. Gulf Coast region, the refined petroleum
products market in the same region, the relationship between these
two markets, fulfilling contract demands, and other factors that
may impact our operations, financial condition, and cash flows.
Under our inventory risk management policy, commodity futures
contracts may be used to mitigate the change in value for certain
of our refined petroleum product inventories subject to market
price fluctuations in our inventory. The physical inventory volumes
are not exchanged, and these contracts are net settled with
cash.
When
active, the fair value of commodity futures contracts is reflected
in our consolidated balance sheets and the related net gain or loss
is recorded within cost of refined products sold in our
consolidated statements of operations. Quoted prices for identical
assets or liabilities in active markets (Level 1) are considered to
determine the fair values for marking to market the financial
instruments at each period end. Commodity transactions are executed
to minimize transaction costs, monitor consolidated net exposures,
and allow for increased responsiveness to changes in market
factors. Due to mark-to-market accounting during the term of the
commodity futures contracts, significant unrealized non-cash net
gains and losses could be recorded in our results of
operations.
At
March 31, 2017, we had no futures contracts of refined petroleum
products and crude oil and condensate that were entered as economic
hedges. We also had no derivative instruments that were reported in
our consolidated balance sheets at March 31, 2017 and December 31,
2016.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
The
following table provides the effect of derivative instruments in
our consolidated statements of operations for the three months
ended March 31, 2017 and 2016:
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
Derivatives
|
|
Statements of Operations Location
|
|
|
|
Commodity
contracts
|
|
Cost
of refined products sold
|
$
-
|
$
(492,528
)
|
|
(19)
|
Commitments and Contingencies
|
Amended and Restated Operating Agreement
. See “Note
(8) Related Party Transactions” and “Note (20)
Subsequent Events” and “Part II, Item 5. Other
Information” for additional disclosures related to the
Amended and Restated Operating Agreement.
Genesis Agreements
. We were party to the following
agreements with Genesis:
Crude Supply Agreement
. GEL supplied the Nixon Facility with
crude oil and condensate under the Crude Supply Agreement at cost
plus freight expense and any costs associated with hedging. All
crude oil and condensate supplied under the Crude Supply Agreement
was paid for pursuant to the terms of the Joint Marketing Agreement
as described within this section. The Crude Supply Agreement has
terminated.
Joint Marketing Agreement
. Together with GEL, we jointly
marketed and sold certain output produced at the Nixon Facility and
shared the associated gross profits from such sales. Payments for
the sale of certain output produced at the Nixon Facility were made
directly to GEL as collection agent, and associated customers had
to satisfy GEL’s customer credit approval
process.
GEL
materially breached these agreements in April 2016 by refusing to
deliver our operational requirements of crude oil for an extended
period. Consequently, we ceased purchases of crude oil and
condensate from GEL under the Crude Supply Agreement in November
2016 and suspended the marketing and sale of refined petroleum
products under the Joint Marketing Agreement following the
processing of all crude oil and condensate supplied by GEL. The
Joint Marketing Agreement has terminated.
GEL Contract-Related Dispute
. As previously disclosed, we
are involved in an on-going dispute with GEL related to the Crude
Supply Agreement and the Joint Marketing Agreement. Arbitration
proceedings related to the dispute with GEL are currently in
progress. We are unable to predict the outcome of these proceedings
or their ultimate impact, if any, on our business, financial
condition, or results of operations. (See “Legal
Matters” below for a discussion of the current
contract-related dispute with GEL.)
FLNG Easements
. BDPL and FLNG were parties to a Pipeline
Easement dated November 5, 2005 (the “FLNG Pipeline
Easement”) and the FLNG Master Easement Agreement (together
with the FLNG Pipeline Easement, the “FLNG Easements”).
The FLNG Easements provided FLNG and its affiliates: (i) a pipeline
easement and right of way across the BDPL Property to certain
property owned by FLNG and (ii) rights of ingress and egress across
the BDPL Property to the property owned by FLNG. Under the FLNG
Easements, FLNG made payments to us in the amount of $500,000 each
year. The FLNG Easements were terminated in February
2017.
In
February 2017, BDPL sold approximately 15 acres of certain of the
BDPL Property to FLIQ Common Facilities, LLC, an affiliate of FLNG,
for cash proceeds of approximately $535,000. In conjunction with
the sale of real estate, FLNG paid to BDPL approximately $1,336,000
as consideration for the full satisfaction and discharge of
FLNG’s future annual payment and other obligations to BDPL
under the FLNG Easements. Excluding the value of the land from the
proceeds, we recognized a gain totaling $1,834,500 related to the
FLNG transactions for the three months ended March 31,
2017.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
Supplemental Pipeline Bonds
. In August 2015, we received a
letter from the Bureau of Ocean Energy Management (the
“BOEM”) requiring additional supplemental bonds or
acceptable financial assurance of approximately $4.2 million for
existing pipeline rights-of-way. In July 2016, the BOEM issued
Notice to Lessees (“NTL”) No. 2016-N01 (Requiring
Additional Security), which changes the way that lessees and
rights-of-way holders demonstrate financial strength and
reliability to plug and abandon wells, as well as decommission and
remove platforms and pipelines at the end of production or service
activities. The NTL, which changed an earlier supplemental waiver
process to a self-insurance model, became effective in September
2016. Pursuant to the NTL, the BOEM requested that lessees submit
any relevant information needed for an overall financial review of
the lessees account. The BOEM indicated that it would use this
information to evaluate a lessees’ ability to carry out its
obligations and determine whether, and/or how much self-insurance a
lessee can use.
In
October 2016, we received a letter from the BOEM summarizing the
amount required as additional security on our existing pipeline
rights-of-way. The letter, which is a courtesy and does not
constitute a formal order by the BOEM, requested that we provide
additional supplemental pipeline bonds or acceptable financial
reassurance of approximately $4.6 million. At March 31, 2017 and
December 31, 2016, we maintained approximately $0.9 million in
credit and cash-backed pipeline rights-of-way bonds issued to the
BOEM. Of the five (5) pipeline rights-of-ways reflected in the
BOEM’s October 2016 letter:
(i)
the pipeline
associated with one (1) right-of-way was decommissioned in 1997,
and
(ii)
the pipelines
associated with three (3) rights-of-way (Segment Nos. 15635, 13101,
and 9428) are the subject of decommissioning permit requests
submitted to the Bureau of Safety and Environmental Enforcement
(the “BSEE”) by Blue Dolphin in April 2016 (the request
for Segment No. 9428 also requires approval by the U.S. Army Corps
of Engineers). In August 2016, BSEE approved decommissioning
operations for Segment No. 15635. In April 2017, BSEE approved
removal of the junction platform associated with Segment No. 13101,
and the U.S. Army Corps of Engineers posted public notice related
to the decommissioning request for Segment No. 9428.
There
can be no assurance that the BOEM will accept a reduced amount of
supplemental financial assurance or not require additional
supplemental pipeline bonds related to our existing pipeline
rights-of-way. If we are required by the BOEM to provide
significant additional supplemental bonds or acceptable financial
assurance, we may experience a significant and material adverse
effect on our operations, liquidity, and financial
condition.
Financing Agreements
. (See “Note (11) Long-Term Debt,
Net” for additional disclosures related to financing
agreements.)
Nixon Facility Expansion
. W
e
have made and continue to make
capital and efficiency improvements to the Nixon Facility.
Therefore, we incurred and will continue to incur capital
expenditures related to these improvements, which include, among
other things, facility and land improvements and construction of
additional petroleum storage tanks.
Legal Matters
.
GEL Contract-Related Dispute.
As described above under
“Genesis Agreements,” we were party to a variety of
contracts and agreements with Genesis and GEL for the purchase of
crude oil and condensate, transportation of crude oil and
condensate, and other services.
In May
2016, GEL filed, in state district court in Harris County, Texas, a
petition and application for a temporary restraining order,
temporary injunction, and permanent injunction (the
“Petition”) against LE and LEH. The Petition alleges
that LE breached the Joint Marketing Agreement, and that LEH
tortiously interfered with the Joint Marketing Agreement, in
connection with an agreement by LEH to supply jet fuel acquired
from LE to a government agency. The Petition primarily sought
temporary and permanent injunctions related to sales of product
from the Nixon Facility to this customer. In June 2016, the court
issued a temporary injunction against LE and LEH as requested by
GEL. LE believes that GEL’s claims in the Petition are
without merit and is defending the matter vigorously.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
In a
matter separate from the above referenced Petition, LE asserted
that GEL materially breached the parties’ agreements in April
2016 by refusing to deliver our operational requirements of crude
oil for an extended period. LE filed a demand for arbitration in
June 2016, pursuant to the terms of a Dispute Resolution Agreement
between the parties (the “Arbitration”). The
Arbitration alleges that GEL breached the Crude Supply Agreement
by:
(i)
overcharging for
crude oil and condensate based on Genesis’ cost as defined in
the Crude Supply Agreement,
(ii)
overcharging for
trucking costs, and
(iii)
significantly
under-delivering crude oil and condensate, resulting in significant
refinery downtime and significant decreases in refinery throughput,
refinery production, and refined petroleum product sales during
2016.
GEL has
made counter claims in the Arbitration with allegations against LE
like those made in the Petition. GEL is seeking substantial
damages, as well as recovery of attorneys’ fee and costs,
totaling approximately $44.0 million in the aggregate, based on
allegations of breach of contract, fraudulent transfer and unjust
enrichment. We believe GEL’s counter claims are without merit
and are defending them vigorously in the
Arbitration.
GEL
recently relinquished its claims for equitable and declaratory
relief and its ability to keep the contracts in force and effect on
a going-forward basis. Thus, the Crude Supply Agreement and the
Joint Marketing Agreement have terminated.
The
contract-related dispute has affected our ability to obtain
financings, prevented us from taking advantage of business
opportunities, disrupted normal business operations, and diverted
management’s focus away from operations. We expect these
effects to continue until the dispute is resolved. We are unable to
predict the outcome of the current proceedings with Genesis and GEL
or their ultimate impact, if any, on our business, financial
condition or results of operations. Accordingly, we have not
recorded an asset or a liability on our consolidated balance sheet
at March 31, 2017. Any determination by the arbitrator that we owe
significant damages to GEL would have a material adverse effect on
our business, liquidity and financial condition and results of
operations. If GEL were awarded significant damages, we may
not be able to pay such damages, which would affect our ability to
continue as a going concern.
Other Legal Matters
. From time to time we are involved in
routine lawsuits, claims, and proceedings incidental to the conduct
of our business, including mechanic’s liens and
administrative proceedings. Management does not believe that such
matters will have a material adverse effect on our financial
position, earnings, or cash flows.
Health, Safety and Environmental Matters
. All our operations
and properties are subject to extensive federal, state, and local
environmental, health, and safety regulations governing, among
other things, the generation, storage, handling, use and
transportation of petroleum and hazardous substances; the emission
and discharge of materials into the environment; waste management;
characteristics and composition of jet fuel and other products; and
the monitoring, reporting and control of greenhouse gas emissions.
Our operations also require numerous permits and authorizations
under various environmental, health, and safety laws and
regulations. Failure to obtain and comply with these permits or
environmental, health, or safety laws generally could result in
fines, penalties or other sanctions, or a revocation of our
permits.
Financial Covenant Defaults
.
At March 31, 2017, LE and LRM were in
violation of certain financial covenants related to the First Term
Loan Due 2034 and Second Term Loan Due 2034. Covenant defaults
under the secured loan agreements would permit Sovereign to declare
the amounts owed under these loan agreements immediately due and
payable, exercise its rights with respect to collateral securing
our obligations under these loan agreements, and/or exercise any
other rights and remedies available.
By
letter dated May 10, 2017, Sovereign waived the financial covenant
defaults as of March 31, 2017. However, the debt associated with
these loans was classified within the current portion of long-term
debt on our consolidated balance sheets due to the uncertainty of
our ability to meet the financial covenants in the future. There
can be no assurance that Sovereign will provide future waivers,
which may have an adverse impact on our financial position and
results of operations.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Notes
to Consolidated Financial Statements
(Continued)
LEH Note
On May
9, 2017, the Board approved the LEH Note effective March 31, 2017.
The LEH Note has a principal amount of $440,815, accrues interest,
compounded annually, at a rate of 8.00%, and matures in January
2019. Under the LEH Note, prepayment, in whole or in part, is
permissible at any time and from time to time, without premium or
penalty. (See “Note (8) Related Party Transactions” and
“Part II, Item 5. Other Information” for additional
disclosures related to the LEH Note.)
Amended and Restated Ingleside Note
On May
9, 2017, the Board approved the Amended and Restated Ingleside
Note. The Amended and Restated Ingleside Note has a principal
amount of $1,195,723, accrues interest, compounded annually, at a
rate of 8.00%, and matures in January 2019. Under the Amended and
Restated Ingleside Note, prepayment, in whole or in part, is
permissible at any time and from time to time, without premium or
penalty. (See “Note (8) Related Party Transactions” and
“Part II, Item 5. Other Information” for additional
disclosures related to the Amended and Restated Ingleside
Note.)
Amended and Restated Carroll Note
On May
9, 2017, the Board approved the Amended and Restated Carroll Note.
The Amended and Restated Carroll Note has a principal amount of
$775,442, accrues interest, compounded annually, at a rate of
8.00%, and matures in January 2019. Under the Amended and Restated
Carroll Note, prepayment, in whole or in part, is permissible at
any time and from time to time, without premium or penalty. (See
“Note (8) Related Party Transactions” and “Part
II, Item 5. Other Information” for additional disclosures
related to the Amended and Restated Carroll Note.)
Amended and Restated Operating Agreement
.
As
previously disclosed, we are involved in an on-going dispute with
GEL related to the Crude Supply Agreement and Joint Marketing
Agreement, each dated August 12, 2011. Pursuant to an Operating
Agreement (the “Operating Agreement”) dated February
15, 2012 between LEH, LE, and Blue Dolphin, the Operating Agreement
expired upon the earliest to occur of: (a) the date of the
termination of the Joint Marketing Agreement pursuant to its terms,
(b) August 2018, or (c) upon written notice of either party of a
material breach of the Operating Agreement by the other
party.
Due to
termination of the Joint Marketing Agreement, the Operating
Agreement was amended and restated to modify the compensation and
term provisions. The Board approved the Amended and Restated
Operating Agreement on May 9, 2017 with an effective date of April
1, 2017. For services rendered under the Amended and Restated
Operating Agreement, we reimburse LEH at cost plus five percent
(5%) for all reasonable Blue Dolphin expenses incurred while LEH
performs the Services. The Amended and Restated Operating Agreement
expires: (i) April 1, 2020, (ii) upon written notice of 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. (See “Note
(8) Related Party Transactions” and “Part II, Item 5.
Other Information” for additional disclosures related to the
Amended and Restated Operating Agreement.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
In this Form 10-Q for the quarterly period ended March 31, 2017
(the Quarterly Report”), references to “Blue
Dolphin,” “we,” “us” and
“our” are to Blue Dolphin Energy Company and its
subsidiaries, unless otherwise indicated or the context otherwise
requires. You should read the following discussion together with
the financial statements and the related notes included elsewhere
in this Quarterly Report, as well as with the risk factors,
financial statements, and related notes included thereto in Form
10-K for the fiscal year ended December 31, 2016 (the “Annual
Report”).
Forward Looking Statements
Certain
statements included in this Quarterly Report, including in this
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations” are forward-looking
statements within the meaning of the Private Securities Litigation
Reform Act of 1935. Forward-looking statements represent
management’s beliefs and assumptions based on currently
available information. Forward-looking statements relate to
matters such as our industry, business strategy, goals and
expectations concerning our market position, future operations,
margins, profitability, capital expenditures, liquidity and capital
resources, 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
●
Insufficient
liquidity to sustain operations because of net losses, working
capital deficits, and other factors, including an adverse change in
our relationship with Genesis Energy, LP (“Genesis”)
and GEL Tex Marketing, LLC (“GEL”), crude supply
issues, and financial covenant defaults in secured loan
agreements.
●
Dangers inherent in
oil and gas operations that could cause disruptions and expose us
to potentially significant losses, costs or liabilities and reduce
our liquidity.
●
Geographic
concentration of our assets, which creates a significant exposure
to the risks of the regional economy.
●
Competition from
companies having greater financial and other
resources.
●
Laws and
regulations regarding personnel and process safety, as well as
environmental, health, and safety, for which failure to comply may
result in substantial fines, criminal sanctions, permit
revocations, injunctions, facility shutdowns, and/or significant
capital expenditures.
●
Insurance coverage
that may be inadequate or expensive.
●
Related party
transactions with Lazarus Energy Holdings, LLC (“LEH”)
and its affiliates, which may cause conflicts of
interest.
●
Failure to comply
with certain financial covenants related to certain secured loan
agreements.
●
Our ability to use
net operating loss (“NOL”) carryforwards to offset
future taxable income for U.S. federal income tax purposes, which
are subject to limitation.
●
Terrorist attacks,
cyber-attacks, threats of war, or actual war may negatively affect
our operations, financial condition, results of operations, and
cash flows.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Risks Related to Our Refinery Operations Business
Segment
●
An unfavorable
outcome of the contract-related dispute with GEL, which could have
a material adverse effect on us.
●
A determination by
management, and the report of our independent registered public
accounting firm that expresses, substantial doubt about our ability
to continue as a going concern.
●
Volatility of
refining margins.
●
Volatility of crude
oil, other feedstocks, refined petroleum products, and fuel and
utility services.
●
Our ability to
acquire sufficient levels of crude oil on favorable terms to
operate the Nixon Facility.
●
Refinery downtime,
which could result in lost margin opportunity, increased
maintenance costs, increased inventory, and a reduction in cash
available for payment of our obligations.
●
Capital needs for
which our internally generated cash flows and other sources of
liquidity may not be adequate.
●
Our dependence on
LEH for financing and management of our properties.
●
Loss of executive
officers or key employees, as well as a shortage of skilled labor
or disruptions in our labor force, which may make it difficult to
maintain productivity.
●
Loss of market
share by a key customer or consolidation among our customer
base.
●
Failure to grow or
maintain the market share for our refined petroleum
products.
●
Our reliance on
third-parties for the transportation of crude oil and condensate
into and refined petroleum products out of the Nixon
Facility.
●
Interruptions in
the supply of crude oil and condensate sourced in the Eagle Ford
Shale.
●
Changes in the
supply/demand balance in the Eagle Ford Shale that could result in
lower margins on refined petroleum products.
●
Hedging of our
refined petroleum products and crude oil and condensate inventory,
which may limit our gains and expose us to other
risks.
●
Regulation of
greenhouse gas emissions, which could increase our operational
costs and reduce demand for our products.
Risks Related to Our Pipelines and Oil and Gas
Properties
●
Required increases
in bonds or other sureties to maintain compliance with regulatory
requirements, which could significantly impact our liquidity and
financial condition.
●
More stringent
regulatory requirements related to asset retirement obligations
(“AROs”), which could significantly increase our
estimated future AROs.
Any one
of these factors or a combination of these factors could materially
affect our future results of operations and could influence whether
any forward-looking statements ultimately prove to be accurate. Our
forward-looking statements are not guarantees of future
performance, and actual results and future performance may differ
materially from those suggested in any forward-looking statements.
We do not intend to update these statements unless we are required
to do so.
Company Overview
Blue
Dolphin is primarily an independent refiner and marketer of
petroleum products. Our primary asset is a 15,000-bpd crude oil and
condensate processing facility that is in Nixon, Texas (the
“Nixon Facility”). As part of our refinery business
segment, we also conduct petroleum storage and terminaling
operations under third-party lease agreements at the Nixon
Facility. We also own pipeline assets and have leasehold interests
in oil and gas wells. The pipelines and oil and gas wells are
inactive. We maintain a website at
http://www.blue-dolphin-energy.com
.
Information on or accessible through our website is not
incorporated by reference in or otherwise made a part of this
Quarterly Report.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Major Influences on Results of Operations
As a
margin-based business, our refinery operations are primarily
affected by crack spreads, our product slate, and refinery
downtime.
Crack Spreads
The
prices of crude oil and refined petroleum products are the most
significant driver of margins, and they have historically been
subject to wide fluctuations. Our cost to acquire crude oil and
condensate and the price for which our refined petroleum products
are ultimately sold depend on the economics of supply and demand.
Supply and demand are affected by numerous factors, most, if not
all, of which are beyond our control, including:
●
Domestic and
foreign market conditions, political affairs, and economic
developments;
●
Import supply
levels and export opportunities;
●
Existing domestic
inventory levels;
●
Operating and
production levels of competing refineries;
●
Expansion and/or
upgrades of competitors’ facilities;
●
Governmental
regulations (e.g., mandated renewable fuels standards, proposed
climate change laws and regulations, and increased mileage
standards for vehicles);
●
Availability of and
access to transportation infrastructure;
●
Availability of
competing fuels (e.g., renewables); and
For the
three months ended March 31, 2017 (the “Current
Period”), our average crack spread for refined petroleum
products was $0.14 per bbl compared to $0.21 per bbl for the three
months ended March 31, 2016 (the “Prior Period”),
reflecting a decrease of $0.07 per bbl. Our gross profit increased
$312,448, or 60%, between the periods because of increased tank
rental revenue from more tank leases in the Current Period compared
to the Prior Period.
Product Slate
Management periodically determines whether to change product mix,
as well as maintain, increase, or decrease inventory levels based
on various factors. These factors include the crude oil pricing
market in the U.S. Gulf Coast region, the refined petroleum
products market in the same region, the relationship between these
two markets, fulfilling contract demands, and other factors that
may impact our operations, financial condition, and cash
flows.
Recent changes to our product slate include increased production of
military jet fuel and the sale of low-sulfur diesel to customers
that export to Mexico. Military jet fuel and Jet A fuel are
produced by separating the distillate stream into kerosene and
diesel and blending the kerosene with a portion of the heavy
naphtha stream. Military jet fuel and Jet A fuel
are considered higher value products that significantly upgrade the
value of the naphtha component. Exports of low-sulfur diesel to
Mexico offset weaker demand for HOBM in the U.S. local market. HOBM
and low-sulfur diesel are produced from our heavy oil
stream.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Refinery Downtime
The safe and reliable operation of the Nixon Facility is key to our
financial performance and results of operations, and we are
particularly vulnerable to disruptions in our operations because
all our refining operations are conducted at a single facility.
Although operating at anticipated levels, the Nixon Facility is
still in a recommissioning phase and may require unscheduled
downtime for unanticipated reasons, including maintenance and
repairs, voluntary regulatory compliance measures, or cessation or
suspension by regulatory authorities. Occasionally, the Nixon
Facility experiences a temporary shutdown due to power outages from
high winds and thunderstorms. In such cases, we must initiate a
standard refinery start-up process, which can last several days. We
are typically able to resume normal operations the next day. Any
scheduled or unscheduled downtime may result in lost margin
opportunity, increased maintenance expense and a build-up of
refined petroleum products inventory, which could reduce our
ability to meet our payment obligations.
Key Relationships
Relationship with LEH
We are
party to a variety of contracts and agreements with LEH, including
an Amended and Restated Operating Agreement, a Jet Fuel Sales
Agreement, a Terminal Services Agreement, a Loan and Security
Agreement, and a Promissory Note. In addition, we currently rely on
advances from LEH to fund our working capital requirements. LEH
may, but is not required to, fund our working capital requirements.
There can be no assurances that LEH will continue to fund our
working capital requirements. (See “Part I, Item 1. Financial
Statements – Note (8) Related Party Transactions” and
“Note (20) Subsequent Events” and “Part II, Item
5. Other Information” for disclosures related to agreements
that we have in place with LEH.)
Relationship with Genesis and GEL
We were
party to a variety of contracts and agreements with Genesis and GEL
for the purchase of crude oil and condensate, transportation of
crude oil and condensate, and other services. (See “Part I,
Item 1. Financial Statements – Note (19) Commitments and
Contingencies – Genesis Agreements” for a summary of
the contracts and agreements that we had with Genesis and GEL.) As
previously disclosed, we are involved in an ongoing-dispute with
GEL related to certain of these agreements, which have terminated.
Arbitration proceedings related to the dispute with GEL are
currently in progress. We are unable to predict the outcome of
these proceedings or their ultimate impact, if any, on our
business, financial condition, or results of operations. (See
“Part I, Item 1A. Risk Factors” in our Annual Report,
as well as “Part I, Item 1. Financial Statements – Note
(19) Commitments and Contingencies – Legal Matters” in
this Quarterly Report for disclosures related to the current
contract-related dispute with GEL.)
Results of Operations
Effective January 1, 2017, we began reporting a single business
segment – Refinery Operations. Business activities related to
our Refinery Operations business segment are conducted at the Nixon
Facility. Due to their small size, current and prior period amounts
associated with Pipeline Transportation operations were
reclassified to Corporate and Other. Pipeline Transportation
operations diminished significantly as services to third-parties
ceased and third-party wells along our pipeline corridor were
permanently abandoned.
In this Results of Operations section, we review:
●
Definitions
of key financial performance measures used by
management;
●
Consolidated
results (reflect financial results for our Refinery Operations
business segment and Corporate and Other);
●
Non-GAAP
financial results; and
●
Refinery
Operations business segment results.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
GLOSSARY OF SELECTED FINANCIAL AND PERFORMANCE
MEASURES
Management uses generally accepted accounting principles
(“GAAP”) and certain non-GAAP performance measures to
assess our results of operations. Certain performance measures used
by management to assess our operating results and the effectiveness
of our business segment are considered non-GAAP performance
measures. These performance measures may differ from similar
calculations used by other companies within the petroleum industry,
thereby limiting their usefulness as a comparative
measure.
We refer to certain refinery throughput and production data in the
explanation of our period over period changes in results of
operations. For our consolidated results, we refer to our
consolidated statements of operations in the explanation of our
period over period changes in results of operations.
Below are definitions of key financial performance measures used by
management:
Adjusted Earnings Before Interest, Income Taxes and Depreciation
(“EBITDA”)
.
Reflects EBITDA excluding the JMA Profit
Share.
-
Refinery
Operations Adjusted EBITDA
.
Reflects adjusted EBITDA for our refinery operations business
segment.
-
Total
Adjusted EBITDA
.
Reflects adjusted EBITDA for our refinery
operations business segment, as well as corporate and
other.
Capacity Utilization Rate
. A percentage measure that
indicates the amount of available capacity that is being used in a
refinery or transported through a pipeline. With respect to the
Nixon Facility, the rate is calculated by dividing total refinery
throughput or total refinery production on a bpd basis by the total
capacity of the Nixon Facility (currently 15,000 bpd).
Cost of Refined Products Sold
.
Primarily includes purchased crude oil and
condensate costs, as well as transportation, freight and storage
costs.
Depletion, Depreciation and Amortization
. Represents property and equipment, as well as
intangible assets that are depreciated or amortized based on the
straight-line method over the estimated useful life of the related
asset.
Downtime
. Scheduled and/or unscheduled periods in which the
Nixon Facility is not operating. Downtime may occur for a variety
of reasons, including bad weather, power failures, preventive
maintenance, equipment inspection, equipment repair due to
mechanical failure, voluntary regulatory compliance measures,
cessation or suspension by regulatory authorities, and inventory
management.
Easement, Interest and Other Income
.
Reflects income related to an easement agreement
with FLNG Land II, Inc., a Delaware corporation
(“FLNG”); recorded as land easement revenue and
recognized monthly as earned. See “Part I, Item 1. Financial
Statements – Note (19) Commitments and Contingencies –
FLNG Easements” for additional discussion of easement
income.
EBITDA
.
Reflects earnings before: (i) interest income
(expense), (ii) income taxes, and (iii) depreciation and
amortization.
-
Refinery
Operations EBITDA
. Reflects
EBITDA for our refinery operations business
segment.
-
Total
EBITDA
. Reflects EBITDA for our
refinery operations business segment, as well as corporate and
other.
General and Administrative Expenses
.
Primarily include corporate costs, such as
accounting and legal fees, office lease expenses, and
administrative expenses.
Gross Profit
.
Calculated as total revenue less cost of refined
products sold.
Income Tax Expense
.
Includes federal and state taxes, as well as
deferred taxes, arising from temporary differences between income
for financial reporting and income tax
purposes.
JMA Profit Share
.
Under the Joint Marketing Agreement, which has
terminated, Gross Profits (as defined therein) were shared between
the parties. Represents the
GEL
Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement; an indirect
operating expense. If Gross Profits were positive, then the JMA
Profit Share reflected an expense to us. If Gross Profits were
negative, then the JMA Profit Share reflected a credit to
us.
Net Income
. Represents total
revenue from operations less total cost of operations, total other
expense, and income tax expense.
Operating Days
. Represents the number of days in a period in
which the Nixon Facility operated. Operating days is calculated by
subtracting downtime in a period from calendar days in the same
period.
Refinery Operating Expenses
.
Reflect the direct operating expenses of the Nixon
Facility, including direct costs of labor, maintenance materials
and services, chemicals and catalysts and utilities. Includes fees
paid to: (i) LEH to manage and operate the Nixon Facility pursuant
to the Amended and Restated Operating Agreement and (ii) Ingleside
Crude, LLC to lease petroleum storage tanks to meet periodic,
additional storage needs under the Amended and Restated Tank Lease
Agreement.
Refinery Operating Income
.
Reflects refined petroleum product
sales less direct operating costs (including cost of refined
products sold and refinery operating expenses) and the JMA profit
share.
Revenue from Operations
.
Primarily consists of refined petroleum product sales, but also
includes tank rental revenue.
Excise and other taxes that
are collected from customers and remitted to governmental
authorities are not included in revenue. Other revenue relates to
fees received from pipeline transportation services, which ceased
in 2016.
Total Refinery Production
. Refers to the volume processed as
output through the Nixon Facility. Refinery production includes
finished petroleum products, such as jet fuel and exportable
low-sulfur diesel, and intermediate petroleum products, such as
LPG, naphtha, HOBM and AGO.
Total Refinery Throughput
.
Refers to the volume processed as
input through the Nixon Facility. Refinery throughput includes
crude oil and condensate and other feedstocks.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Consolidated Results
Total Revenue from Operations
. For the Current Period we had
total revenue from operations of $52,605,749 compared to total
revenue from operations of $31,512,276 for the Prior Period. The
approximate 67% increase in total revenue from operations between
the periods was the result of higher refined product prices per bbl
in the Current Period compared to the Prior Period.
Cost of Refined Products Sold
. Cost of refined products sold
was $51,774,502 for the Current Period compared to $30,993,477 for
the Prior Period. The approximate 67% increase in cost of refined
products sold was the result of higher crude costs per bbl in the
Current Period compared to the Prior Period.
Gross Profit
. For the Current Period gross profit totaled
$831,247 compared to $518,766 for the Prior Period, representing an
increase of $312,448. The approximate 60% increase in gross profit
between the periods related to additional tank rental revenue from
more tank leases in the Current Period compared to the Prior
Period.
Refinery Operating Expenses
. We recorded refinery operating
expenses of $2,813,103 in the Current Period compared to $3,437,015
in the Prior Period, a decrease of approximately 18%. Refinery
operating expenses per bbl of throughput were $2.80 in the Current
Period compared to $2.90 in the Prior Period. The $0.10 decrease in
refinery operating expenses per bbl of throughput between the
periods was the result of a decrease in off-site tank leasing
expense under the Amended and Restated Tank Lease Agreement in the
Current Period. (See “Part I, Item 1. Financial Statements
– Note (8) Related Party Transactions” for additional
disclosures related to components of refinery operating
expenses.)
JMA Profit Share.
For the Current Period,
the JMA Profit Share was $0 compared to a credit
of $671,092 for the Prior Period. Elimination of the JMA
Profit Share between the periods was the result of termination of
the Joint Marketing Agreement.
(See “Part I, Item 1.
Financial Statements – Note (19) Commitments and
Contingencies – Genesis Agreements” for further
discussion related to the Joint Marketing Agreement, JMA Profit
Share, Gross Profits and the contract-related dispute with
GEL.)
General and Administrative Expenses
. We incurred general and
administrative expenses of $906,090 in the Current Period compared
to $357,004 in the Prior Period. The significant increase in
general and administrative expenses in the Current Period compared
to the Prior Period primarily related to an increase in legal fees
associated with the contract-related dispute with GEL.
Depletion, Depreciation and Amortization
. We recorded
depletion, depreciation and amortization expenses of $451,025 in
the Current Period compared to $440,453 in the Prior Period. The
approximate 2% increase in depletion, depreciation and amortization
expenses for the Current Period compared to the Prior Period
primarily related to additional depreciable refinery assets that
were placed in service.
Easement, Interest and Other Income.
We recorded $381,993 in easement, interest and
other income for the Current Period compared to $131,763 in the
Prior Period. The significant increase between the periods was due
to the sale of land to an FLNG affiliate, which accelerated revenue
recognition from
FLNG’s annual payments to BDPL under
a Master Easement Agreement (the “FLNG Master Easement
Agreements”). The FLNG Master Easement Agreement was
terminated in February 2017 as part of the land sale transaction.
(See “Part I, Item 1. Financial Statements – Note (19)
Commitments and Contingencies – FLNG Easements” for
additional discussion related to FLNG.)
Gain on Disposal of Property
. We recognized a gain related
to the FLNG transactions totaling $1,834,500 in the Current Period.
In February 2017, BDPL sold approximately 15 acres of certain of
the property owned by BDPL located in Brazoria County Texas (the
"BDPL Property") to FLIQ Common Facilities, LLC, an affiliate of
FLNG. In conjunction with the sale of real estate, the FLNG
Easements were terminated. (See “Part I, Item 1. Financial
Statements – Note (19) Commitments and Contingencies –
FLNG Easements” for additional discussion related to
FLNG.)
Income Tax Benefit
. We recognized an income tax benefit of
$0 in the Current Period compared to $1,165,901 in the Prior
Period. Income tax benefit in the Prior Period primarily related to
deferred federal income taxes. We recorded a full valuation
allowance against deferred tax assets as of March 31, 2017 and
December 31, 2016 (See “Part I, Item 1. Financial Statements
– Note (16) Income Taxes” for additional disclosures
related to income taxes.)
Net Income (Loss)
. For the Current Period, we reported a net
loss of $1,849,714 or a loss of $0.18 per share, compared to net
loss of $2,149,084, or loss of $0.21 per share, for the Prior
Period. The $0.03 per share improvement in net loss between the
periods was the result of a gain on the sale of property and lower
refinery operating expenses. Refinery operating expense was lower
in the Current Period due to a decrease in off-site tank leasing
expense under the Amended and Restated Tank Lease
Agreement.
Non-GAAP Financial Measures
To supplement our consolidated results, management uses EBITDA, a
non-GAAP financial measures, to help investors evaluate our ongoing
operating results and allow for greater transparency in reviewing
our overall financial, operational and economic performance. EBITDA
is reconciled to GAAP-based results below. EBITDA should not be
considered an alternative for GAAP results. EBITDA is provided to
enhance an overall understanding of our financial performance for
the applicable periods and is an indicator management believes is
relevant and useful. EBITDA may differ from similar calculations
used by other companies within the petroleum industry, thereby
limiting its usefulness as a comparative measure. (See “Part
I, Item 1. Financial Statements” for comparative GAAP
results.)
EBITDA Reconciliation to GAAP
.
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
from operations
|
$
52,605,749
|
$
-
|
$
52,605,749
|
$
31,484,624
|
$
27,652
|
$
31,512,276
|
|
Less: cost of operations
(1)
|
(55,195,761
)
|
(430,622
)
|
(55,626,383
)
|
(34,422,853
)
|
(346,903
)
|
(34,769,756
)
|
|
Other non-interest income
(2)
|
-
|
2,216,251
|
2,216,251
|
-
|
130,665
|
130,665
|
|
Less: JMA Profit Share
(3)
|
-
|
-
|
-
|
671,092
|
-
|
671,092
|
|
EBITDA
|
$
(2,590,012
)
|
$
1,785,629
|
$
(804,383
)
|
$
(2,267,137
)
|
$
(188,586
)
|
$
(2,455,723
)
|
|
|
|
|
|
|
|
|
Depletion, depreciation and
|
|
|
|
|
|
|
amortization
|
|
|
(451,025
)
|
|
|
(440,453
)
|
|
Interest
expense, net
|
|
|
(594,542
)
|
|
|
(418,809
)
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
(1,849,950
)
|
|
|
(3,314,985
)
|
|
|
|
|
|
|
|
|
|
Income
tax benefit
|
|
|
-
|
|
|
1,165,901
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
$
(1,849,950
)
|
|
|
$
(2,149,084
)
|
|
(1)
|
Operation
cost within the Refinery Operations segment includes related
general and administrative expenses. Operation cost within
Corporate and Other includes general and administrative expenses
associated with corporate maintenance costs (such as accounting
fees, director fees, and legal expense), as well as expenses
associated with our pipeline assets and oil and/or gas leasehold
interests (such as accretion and impairment expenses).
|
|
(2)
|
Other
non-interest income reflects FLNG Land II, Inc.
(“FLNG”) easement revenue. (See “Part I, Item 1.
Financial Statements – Note (19) Commitments and
Contingencies – FLNG Easements” for further discussion
related to FLNG.)
|
|
(3)
|
The JMA Profit Share represents the
GEL
Profit Share plus the Performance Fee for the
period pursuant to the Joint Marketing Agreement, which has
terminated. (See “Part I, Item 1. Financial Statements
– Note (19) Commitments and Contingencies – Genesis
Agreements” for further discussion of the Joint Marketing
Agreement and the contract-related dispute with
GEL.)
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
EBITDA Current Period Compared to Prior Period
.
Refinery Operations EBITDA.
Refinery operations EBITDA for
the Current Period was a loss of $2,590,012 compared to a loss of
$2,267,137 for the Prior Period. The $322,875 decrease in refinery
operations EBITDA between the periods was the result of higher
crude costs per bbl in the Current Period compared to the Prior
Period.
Total EBITDA.
Total EBITDA for the Current Period was a loss
of $804,383 compared to a loss of $2,455,723 for the Prior Period.
This represented an improvement of $1,651,340 for the Current
Period compared to the Prior Period. The improvement in total
EBITDA related to a gain on the sale of property in the Current
Period.
Refinery Operations Business Segment Results
During
the Current Period, our average crack spread was $0.14 per bbl
compared to $0.21 per bbl for the Prior Period, reflecting a
decrease of $0.07 per bbl. Despite the decrease in crack spread,
our gross profit increased $312,448, or 60%, between the periods
because of increased tank rental revenue from more tank leases in
the Current Period compared to the Prior Period.
Refinery Throughput and Production Data
.
Following are
refinery operational metrics for the Nixon Facility:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
Calendar
Days
|
90
|
91
|
|
Refinery
downtime
|
(10
)
|
-
|
|
Operating
Days
|
80
|
91
|
|
|
|
|
|
Total
refinery throughput (bbls)
|
1,004,172
|
1,183,806
|
|
Operating
days:
|
|
|
|
bpd
|
12,552
|
13,009
|
|
Capacity
utilization rate
|
83.7
%
|
86.7
%
|
|
Calendar
days:
|
|
|
|
bpd
|
11,157
|
13,009
|
|
Capacity
utilization rate
|
74.4
%
|
86.7
%
|
|
|
|
|
|
Total
refinery production (bbls)
|
969,734
|
1,154,307
|
|
Operating
days:
|
|
|
|
bpd
|
12,122
|
12,685
|
|
Capacity
utilization rate
|
80.8
%
|
84.6
%
|
|
Calendar
days:
|
|
|
|
bpd
|
10,775
|
12,685
|
|
Capacity
utilization rate
|
71.8
%
|
84.6
%
|
|
Note:
|
The
difference between total refinery throughput (volume processed as
input) and total refinery production (volume processed as output)
represents refinery fuel use and loss.
|
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Current Period Compared to Prior Period
.
Refinery Downtime
.
The
Nixon Facility operated for a total of 80 days in the Current
Period, reflecting 10 days of refinery downtime. Comparatively, the
Nixon Facility operated for a total of 91 days in the Prior Period,
reflecting no refinery downtime. Refinery downtime in the Current
Period related to a maintenance turnaround.
Total Refinery Throughput
. The Nixon Facility processed
1,004,172 bbls of crude oil and condensate for the Current Period
compared to 1,183,806 bbls of crude oil and condensate for the
Prior Period, a decrease of 15%. On an operating day basis, total
refinery throughput totaled 12,552 bpd in the Current Period
compared to 13,009 bpd for the Prior Period, a decrease of 457 bpd.
On a calendar day basis, total refinery throughput totaled 11,157
bpd in the Current Period compared to 13,009 bpd for the Prior
Period, a decrease of 1,851 bpd. The decrease between the periods
related to refinery downtime in the Current Period.
Total Refinery Production
. The Nixon Facility produced
969,734 bbls of refined petroleum products for the Current Period
compared to 1,154,307 bbls of refined petroleum products for the
Prior Period, a decrease of 16%. On an operating day basis, total
refinery production totaled 12,122 bpd in the Current Period
compared to 12,685 bpd for the Prior Period, a decrease of 563 bpd.
On a calendar day basis, total refinery production totaled 10,775
bpd in the Current Period compared to 12,685 bpd for the Prior
Period, a decrease of 1,910 bpd. The decrease between the periods
related to refinery downtime in the Current Period.
Capacity Utilization Rate
. On an operating day basis, the
capacity utilization rate for refinery throughput and refinery
production decreased approximately 3% and 4%, respectively, between
the periods. On a calendar day basis, the capacity utilization rate
for refinery throughput and refinery production decreased
approximately 12% and 13%, respectively, between the
periods.
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.)
Refined Petroleum Product Economic Hedges
.
Under
our inventory risk management policy, commodity futures contracts
are used to mitigate the volatile change in value for certain of
our refined petroleum product inventories. We had no open commodity
contracts in the Current Period. For the Prior Period, our refinery
operations business segment recognized a loss of $881,512 on
settled transactions and a gain of $1,374,040 on the change in
value of open contracts from December 31, 2015 to March 31,
2016.
Liquidity and Capital Resources
Overview
.
Our
primary use of cash flow is to operate the Nixon Facility, purchase
crude oil and condensate, and fund capital expenditures. Our
primary sources of liquidity have been cash reserves, revenue from
operations, LEH, and borrowings under bank facilities. Our
liquidity was severely constrained in the Current Period,
principally because of lower crack spreads compared to the Prior
Period. As discussed within this “Liquidity and Capital
Resources” section, m
anagement
has determined that there is substantial doubt about our ability to
continue as a going concern due to consecutive quarterly net
losses, insufficient working capital, litigation risk, crude supply
issues, and financial covenant defaults in secured loan agreements.
(See “Part I, Item 1. Financial Statements – Note (1)
Organization – Operating Risks-Going Concern” for
additional discussion related to going
concern.)
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
We are
taking aggressive actions to improve operations and liquidity by:
(i) continuing with Nixon Facility capital improvements, including
upgrading the refinery’s heat exchangers and increasing
petroleum storage tank capacity, (ii) increasing military jet fuel
sales and low-sulfur diesel exports to Mexico, (iii) restructuring
customer contracts as they come up for renewal to incorporate
minimum sales volumes, (iv) working to secure a long-term crude oil
and condensate supply arrangement, (v) exploring alternative
funding sources for crude oil and condensate purchases, and (vi)
seeking additional financing to meet ongoing liquidity needs.
Management is confident that it is taking the necessary steps to
assist the Company in executing its plan. However, there can be no
assurance that our plan will be successful or that we will be able
to obtain additional financing on commercially reasonable terms or
at all.
Crude Oil and Condensate Supplies
.
Operation
of the Nixon Facility depends on our ability to purchase adequate
crude supplies on favorable terms. We currently have in place a
month-to-month evergreen crude supply contract with a major
integrated oil and gas company. We are working to put a long-term
crude supply agreement in place, however, our ability to purchase
crude oil and condensate is dependent on our liquidity and access
to capital, which have been adversely affected by net losses,
working capital deficits, the contract-related dispute with GEL,
and financial covenant defaults in secured loan
agreements.
As
previously disclosed, we are involved in an on-going dispute with
GEL related to the Crude Supply Agreement, which has terminated.
Arbitration proceedings related to the dispute with GEL are
currently in progress. The contract-related dispute has affected
our ability to obtain financings, prevented us from taking
advantage of business opportunities, disrupted normal business
operations, and diverted management’s focus away from
operations. We expect these effects to continue until the
dispute is resolved, which management believes will occur in the
first half of 2017. We are unable to predict the outcome of the
current proceedings with GEL or their ultimate impact, if any, on
our business, financial condition or results of
operations.
We are
pursuing alternative sources to finance crude oil and condensate
acquisition costs, including commodity sale and repurchase
programs, inventory financing, debt financing, equity financing, or
other means. We may not be successful in consummating suitable
financing transactions in the period required or at all, securing
financing on terms favorable to us, or obtaining crude oil and
condensate at the levels needed to earn a profit and/or safely
operate the Nixon Facility, any of which could adversely affect our
business, results of operations and financial
condition.
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Cash Flow
.
Our
cash flow from operations for the periods indicated was as
follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
|
|
Adjusted
income (loss) from operations
|
$
(1,294,960
)
|
$
(4,308,132
)
|
|
Change
in assets and current liabilities
|
(1,078,883
)
|
3,905,612
|
|
|
|
|
|
Total
cash flow from operations
|
(2,373,843
)
|
(402,520
)
|
|
|
|
|
|
Cash
inflows (outflows)
|
|
|
|
Proceeds
from issuance of debt
|
1,097,290
|
-
|
|
Payments
on debt
|
(473,578
)
|
(478,431
)
|
|
Capital
expenditures
|
(810,832
)
|
(3,639,645
)
|
|
|
|
|
|
Total
cash outflows
|
(187,120
)
|
(4,118,076
)
|
|
|
|
|
|
Total
change in cash flows
|
$
(2,560,963
)
|
$
(4,520,596
)
|
We
experienced negative cash flow from operations of $2,373,843 for
the Current Period compared to negative cash flow from operations
of $402,520 for the Prior Period, reflecting a $1,971,323 decrease
in cash flow from operations between the periods. The decrease in
cash flow from operations was primarily the result of decreases in
accounts payable.
Working Capital
.
During
the Current Period, we obtained working capital from the issuance
of debt totaling $1,097,290.
We had a
working capital deficit of $42,282,742 at March 31, 2017 compared
to a working capital deficit of $37,812,263 at December 31, 2016.
Excluding long-term debt, we had a working capital deficit of
$9,211,863 at March 31, 2017, compared to working capital of
$5,599,927 at December 31, 2016. The significant increase in
working capital deficit between the periods primarily related to a
decrease in cash and cash equivalents due to inventory
buildup.
As
discussed elsewhere within this “Liquidity and Capital
Resources” section, the contract-related dispute with GEL has
affected our ability to obtain working capital through financings.
We expect this to continue until the dispute is resolved, which
management believes will occur in the first half of
2017.
To meet
ongoing operational needs, we are exploring alternative funding
sources, including inventory financing, to improve available
working capital. We are also relying on LEH to fund working capital
requirements when cash reserves and revenue from operations,
including sales of refined petroleum products and rental of
petroleum storage tanks, are insufficient to fund our working
capital requirements. There can be no assurance that we will be
able to obtain additional financing on commercially reasonable
terms or at all, or that LEH will continue to fund our working
capital requirements when our internally generated cash flows and
other sources of liquidity are inadequate.
Our
short-term working capital needs are primarily related to
acquisition of crude oil and condensate to operate the Nixon
Facility, repayment of debt obligations, and capital expenditures
for maintenance, upgrades, and refurbishment of equipment at the
Nixon Facility. Our long-term working capital needs are primarily
related to repayment of long-term debt obligations. In addition, we
continue to utilize capital to reduce operational, safety and
environmental risks. We have taken standard steps to conserve
working capital and reduce costs. These steps include
renegotiation/bidding of services and support contracts as they
come up for renewal, reducing personnel overtime hours, delaying
payments to vendors, and/or renegotiating alternative payment
terms.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Capital Spending
.
Capital
improvements primarily relate to construction of new petroleum
storage tanks to add to existing petroleum storage tank capacity.
We are working to complete several new tanks in which construction
was began during 2016. New petroleum storage tanks at the Nixon
Facility support future increased refinery throughput, allow for
the purchase of different crude types to maximize product yields
and margins, and provide an opportunity to generate additional tank
rental revenue by leasing to third-parties. When expansion of the
Nixon Facility is complete, total crude oil, condensate, and
refined petroleum product storage capacity will exceed 1,000,000
bbls.
Capital
expenditures at the Nixon Facility are being funded by Sovereign
Bank (“Sovereign”) through long-term debt that we
secured in 2015. Available funds under these loans are reflected in
restricted cash (current and non-current portions) on our
consolidated balance sheets. Restricted cash (current portion)
represents funds to pay outstanding construction invoices and to
fund construction contingencies. Restricted cash (current portion)
totaled $2,756,713 and $3,347,835 at March 31, 2017 and December
31, 2016, respectively. Restricted cash, non-current represents
funds held in our disbursement account with Sovereign to complete
construction of new petroleum storage tanks.
Restricted cash, noncurrent totaled $765,092 and
$1,582,305 at March 31, 2017 and December 31, 2016,
respectively.
Capital expenditures as of the dates indicated were as
follows:
|
|
Three Months Ended March 31,
|
|
|
|
|
|
|
|
|
|
Capital
expenditures financed by:
|
|
|
|
Cash
disbursements
|
$
810,832
|
$
3,639,645
|
|
Accounts payable
(1)
|
1,220,262
|
1,106,205
|
|
|
$
2,031,094
|
$
4,745,850
|
(1)
Represents
construction-related vendor invoices awaiting payment from the loan
disbursement account.
We estimate remaining capital spending in 2017 to approximate $2.5
million. Capital expenditures, which will be funded by remaining
amounts available under bank facilities secured in 2015 with
Sovereign, will primarily be for completion of petroleum storage
tanks at the Nixon Facility.
See “Part I, Item 1. Financial Statements – Note (11)
Long-Term Debt, Net” for additional disclosures related to
borrowings for capital spending.
Contractual Obligations
.
Related Party
. See “Part I, Item 1. Financial
Statements – Note (8) Related Party Transactions” in
this Quarterly Report for a summary of the agreements we have in
place with related parties.
Genesis
. See “Part I,
Item 1A. Risk Factors” in our Annual Report, as well as
“Part I, Item 1. Financial Statements – Note (19)
Commitments and Contingencies – Genesis Agreements and Legal
Matters” in this Quarterly Report for disclosures related to
the contracts and agreements we had in place with Genesis and GEL
and the current contract-related dispute with
GEL.
Supplemental Pipeline Bonds
. See “Part I, Item 1.
Financial Statements – Note (19) Commitments and
Contingencies – Supplemental Pipeline Bonds” for a
discussion of supplemental pipeline bonding
requirements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Indebtedness
.
The principal balances outstanding on our long-term debt, net
(including related party) for the periods indicated were as
follow:
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Term Loan Due 2034
|
$
23,745,152
|
$
23,924,607
|
|
Second
Term Loan Due 2034
|
9,663,450
|
9,729,853
|
|
LEH
Loan Agreement
|
4,000,000
|
4,000,000
|
|
Amended
and Restated Ingleside Note
|
1,195,723
|
722,278
|
|
Notre
Dame Debt
|
1,300,000
|
1,300,000
|
|
Amended
and Restated Carroll Note
|
775,442
|
592,412
|
|
LEH
Note
|
440,815
|
-
|
|
Term
Loan Due 2017
|
-
|
184,994
|
|
Capital
Leases
|
93,153
|
135,879
|
|
|
41,213,735
|
40,590,023
|
|
|
|
|
|
Less:
Current portion of long-term debt, net
|
(33,070,879
)
|
(32,212,336
)
|
|
|
|
|
|
Less:
Unamoritized debt issue costs
|
(2,230,876
)
|
(2,262,997
)
|
|
|
|
|
|
|
$
5,911,980
|
$
6,114,690
|
Additions
to long-term debt totaled $1,097,290 and $0 in the Current Period
and Prior Period, respectively. The addition in the Current Period
related to notes payable and related party promissory notes.
Payments on long-term debt totaled $473,578 for the Current Period
compared to $478,431 in the Prior Period.
At
March 31, 2017, LE and LRM were in violation of certain financial
covenants related to the First Term Loan Due 2034 and Second Term
Loan Due 2034. Covenant defaults under the secured loan agreements
would permit Sovereign to declare the amounts owed under these loan
agreements immediately due and payable, exercise its rights with
respect to collateral securing our obligations under these loan
agreements, and/or exercise any other rights and remedies
available. Sovereign waived the financial covenant defaults as of
March 31, 2017. However, the debt associated with these loans was
classified within the current portion of long-term debt on our
consolidated balance sheets due to the uncertainty of our ability
to meet the financial covenants in the future. There can be no
assurance that Sovereign will provide future waivers, which may
have an adverse impact on our financial position and results of
operations.
See
“Part I, Item 1. Financial Statements – Note (1)
Organization – Operating Risks-Going Concern, Note (11)
Long-Term Debt, Net, and Note (20) Subsequent Events” for
additional disclosures related to long-term debt financial covenant
violations.
See
“Contractual Obligations – Related Party” within
the Liquidity and Capital Resources section for additional
disclosures with respect to related party
indebtedness.
Off-Balance Sheet Arrangements
None.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Critical Accounting Policies
Long-Lived Assets
.
Refinery and Facilities
.
Additions to refinery and facilities assets are capitalized.
Expenditures for repairs and maintenance are included as operating
expenses under the Amended and Restated Operating Agreement and
covered by LEH. Management expects to continue making improvements
to the Nixon Facility based on technological
advances.
We record refinery and facilities at cost less any adjustments for
depreciation or impairment. Adjustment of the asset and the related
accumulated depreciation accounts are made for the refinery and
facilities asset’s retirement and disposal, with the
resulting gain or loss included in the consolidated statements of
operations. For financial reporting purposes, depreciation of
refinery and facilities assets is computed using the straight-line
method using an estimated useful life of 25 years beginning when
the refinery and facilities assets are placed in service. We did
not record any impairment of our refinery and facilities assets for
the years ended December 31, 2016 and 2015.
Pipelines and Facilities Assets
.
We record pipelines and facilities at
cost less any adjustments for depreciation or impairment.
Depreciation is computed using the straight-line method over
estimated useful lives ranging from 10 to 22 years. In accordance
with
Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification
(“ASC”)
guidance on accounting for the
impairment or disposal of long-lived assets, we evaluate our
pipeline and facilities assets for impairment on a periodic basis,
usually annually, and when events or circumstances indicate that
the carrying value of these assets may not be
recoverable.
Management
performed periodic impairment testing of our pipeline and
facilities assets in the fourth quarter of 2016. Upon completion of
that testing, our pipeline assets were fully impaired. All pipeline
transportation services to third-parties have ceased, existing
third-party wells along our pipeline corridor were permanently
abandoned, and no new third-party wells are being drilled near our
pipelines. However, management believes our pipeline assets have
future value based on large-scale, third-party production facility
expansion projects near the pipelines.
Oil and Gas Properties
. We account for our oil and gas
properties using the full-cost method of accounting, whereby all
costs associated with acquisition, exploration and development of
oil and gas properties, including directly related internal costs,
are capitalized on a cost center basis. Amortization of
such costs and estimated future development costs are determined
using the unit-of-production method. Our oil and gas properties had
no production during the three months ended March 31, 2017 and
2016. All leases associated with our oil and gas properties have
expired, and our oil and gas properties were fully impaired in
2011.
Construction in Progress
.
Construction in progress expenditures, which relate to construction
and refurbishment activities at the Nixon Facility, are capitalized
as incurred. Depreciation begins once the asset is placed in
service.
Revenue Recognition
.
Refined Petroleum Products Revenue
. Regarding our finished
products, low-sulfur diesel is sold to customers that export to
Mexico and jet fuel is sold to LEH for resale to a government
agency. Our intermediate products, including LPG, naphtha, HOBM,
and AGO, are primarily sold to wholesalers and refiners for further
blending and processing.
Revenue from
refined petroleum product sales is recognized when sales prices are
fixed or determinable, collectability is reasonably assured, and
title passes. Title passage occurs when refined petroleum products
are delivered in accordance with the terms of the respective sales
agreements, and customers assume the risk of loss when title is
transferred. Transportation, shipping and handling costs incurred
are included in cost of refined products sold. Excise and other
taxes that are collected from customers and remitted to
governmental authorities are not included in
revenue.
Tank Rental Revenue
. Tank rental fees are invoiced monthly
in accordance with the terms of the related lease agreement and
recognized in revenue as earned.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
(Continued)
Asset Retirement Obligations
.
FASB
ASC guidance related to AROs requires that a liability for the
discounted fair value of an ARO be recorded in the period in which
it is incurred and the corresponding cost capitalized by increasing
the carrying amount of the related long-lived asset. The liability
is accreted towards its future value each period, and the
capitalized cost is depreciated over the useful life of the related
asset. If the liability is settled for an amount other than the
recorded amount, a gain or loss is recognized.
Management
has concluded that there is no legal or contractual obligation to
dismantle or remove the refinery and facilities assets. Further,
management believes that these assets have indeterminate lives
under FASB ASC guidance for estimating AROs because dates or ranges
of dates upon which we would retire these assets cannot reasonably
be estimated at this time. When a legal or contractual obligation
to dismantle or remove the refinery and facility assets arises and
a date or range of dates can reasonably be estimated for the
retirement of these assets, we will estimate the cost of performing
the retirement activities and record a liability for the fair value
of that cost using present value techniques.
We
recorded an ARO liability related to future asset retirement costs
associated with dismantling, relocating or disposing of our
offshore platform, pipeline systems and related onshore facilities,
as well as plugging and abandoning wells and restoring land and sea
beds. We developed these cost estimates for each of our assets
based upon regulatory requirements, structural makeup, water depth,
reservoir characteristics, reservoir depth, equipment demand,
current retirement procedures, and construction and engineering
consultations. Because these costs typically extend many years into
the future, estimating future costs are difficult and require
management to make judgments that are subject to future revisions
based upon numerous factors, including changing technology,
political, and regulatory environments. We review our assumptions
and estimates of future abandonment costs on an annual
basis.
Income Taxes
.
We
account for income taxes under FASB ASC guidance related to income
taxes, which requires recognition of income taxes based on amounts
payable with respect to the current reporting period and the
effects of deferred taxes for the expected future tax consequences
of events that have been included in our financial statements or
tax returns. Under this method, deferred tax assets and liabilities
are determined based on the differences between the financial
accounting and tax basis of assets and liabilities, as well as for
operating losses and tax credit carryforwards using enacted tax
rates in effect for the year in which the differences are expected
to reverse.
As of
each reporting date, management considers new evidence, both
positive and negative, to determine the realizability of deferred
tax assets. Management considers whether it is more likely than not
that some portion or all the deferred tax assets will be realized,
which is dependent upon the generation of future taxable income
prior to the expiration of any NOL carryforwards. At March 31, 2017
and December 31, 2016, management determined that cumulative losses
incurred over the prior three-year period provided significant
objective evidence that limited the ability to consider other
subjective evidence, such as projections for future growth. Based
on this evaluation, we recorded a full valuation allowance against
the deferred tax assets as of March 31, 2017 and December 31,
2016.
FASB
ASC guidance related to income taxes also prescribes a recognition
threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to
be taken in a tax return, as well as guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosures, and transition.
(See
“Part I, Item 1. Financial Statements - Note (16) Income
Taxes” for further information related to income
taxes.)
Recently Adopted Accounting Guidance
The
Financial Accounting Standards Board (“FASB”) issues an
Accounting Standards Update (“ASU”) to communicate
changes to the FASB Accounting Standards Codification, including
changes to non-authoritative SEC content. Recently adopted ASUs
include:
ASU 2015-11,
Inventory
(Topic 330):
Simplifying
the Measurement of Inventory
. In July 2015, FASB issued ASU
2015-11, which requires an entity to measure inventory at the lower
of cost or net realizable value. We adopted this accounting
pronouncement effective January 1, 2017. The adoption of ASU
2015-11 did not have a significant impact on our consolidated
financial statements.
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|
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 Chief Financial Officer (principal financial officer), we
conducted an evaluation of the effectiveness of our disclosure
controls and procedures, as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934, as amended
(the “Exchange Act”), as of the end of the period
covered by this Quarterly Report. Based on our evaluation, our
Chief Executive Officer (principal executive officer) and Chief
Financial Officer (principal financial officer) concluded that our
disclosure controls and procedures were effective as of the end of
the period covered by this report to ensure that information
required to be disclosed by us in reports that we file or submit
under the Exchange Act, are recorded, processed, summarized and
reported within the time periods specified in the SEC’s rules
and forms.
Changes in Internal Control over Financial Reporting
Management
concluded that our internal control over financial reporting was
effective as of December 31, 2016. There has been no change in our
internal control over financial reporting (as defined in Rule
13a-15(f) and 15d-15(f) under the Exchange Act) that occurred
during the three months ended March 31, 2017 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” of this Quarterly Report for a
discussion related to controls and procedures.)
Remainder
of Page Intentionally Left Blank
|
BLUE
DOLPHIN ENERGY COMPANY
|
|
FORM
10-Q 3/31/17
|