BLUE DOLPHIN ENERGY COMPANY ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis provides our analysis of our financial performance, financial condition, and significant trends that may affect future performance. All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See "Important Information Regarding Forward-Looking Statements" for factors that could cause actual results to differ materially from those projected. Investors 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 business strategy, risk factors, financial statements and the related notes contained in our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2020 , and our Quarterly Reports on Form 10-Q for the quarterly periods endedMarch 31, 2021 , andJune 30, 2021 .
Overview
Blue Dolphin was formed in 1986 as aDelaware corporation. The company is an independent downstream energy company operating in theGulf Coast region ofthe United States . Operations primarily consist of a light sweet-crude, 15,000-bpd crude distillation tower, and approximately 1.2 million bbls of petroleum storage tank capacity inNixon, Texas . Blue Dolphin trades on the OTCQX under the ticker symbol "BDCO." Assets are primarily organized in two segments: 'refinery operations' (owned by LE) and 'tolling and terminaling services' (owned by LRM and NPS). 'Corporate and other' includes BDPL (inactive pipeline and facilities assets), BDPC (inactive leasehold interests in oil and gas wells), and BDSC (administrative services). For more information related to our business segments, see "Part I, Item 1. Financial Statements - Note (4)".
Unless the context otherwise requires, references in this report to "we," "us," "our," or "ours," refer to Blue Dolphin, one or more of Blue Dolphin's subsidiaries, or all of them taken as a whole
Affiliates
Affiliates controlled approximately 82% of the voting power of our Common Stock as of the filing date of this report. An Affiliate operates and manages all Blue Dolphin properties and funds working capital requirements during periods of working capital deficits. In addition, an Affiliate is a significant customer of our refined products. Blue Dolphin and certain of its subsidiaries are currently parties to a variety of agreements with Affiliates. See "Part I, Item 1. Financial Statements - Note (3)" for additional disclosures related to Affiliate agreements, arrangements, and risks associated with working capital deficits. Business Operations Update General Business Environment. In early 2020, global and national measures taken to address the COVID-19 pandemic, including government-imposed temporary business closures and voluntary shelter-at-home directives, caused oil prices to decline sharply. In addition, actions by members ofOPEC and other producer countries in 2020 concerning oil production and pricing significantly impacted supply and demand in global oil and gas markets. With the introduction and approval of COVID-19 vaccines and increased inoculation rates, global economic activity has shown signs of recovery in 2021. Our Business. Current EIA forecasts show economic growth and mobility increases in the short term. Also, refinery margins are forecasted to improve during the winter months due to projected colder winter temperatures compared to 2020 and low distillates inventory levels. However, forecasts are subject to various factors that are subject to change, including the ongoing impact of COVID-19 and related variants. Management continues to take steps to mitigate risk, avoid business disruptions, manage cash flow, and remain competitive in a volatile commodity price environment. Mitigation steps include: adjusting throughput and production based on market conditions, optimizing receivables and payables by prioritizing payments, managing inventory to avoid buildup, delaying capital spending, and monitoring discretionary spending and nonessential costs. To safeguard personnel, we adopted remote working where possible and social distancing, mask-wearing, and other site-specific precautionary measures where on-site operations are required. We also incentivize personnel to receive the COVID-19 vaccine. We can provide no guarantees that: our business strategy will be successful, Affiliates will continue to fund our working capital needs when we experience working capital deficits, we will meet regulatory requirements to provide additional financial assurance (supplemental pipeline bonds) and decommission offshore pipelines and platform assets, we will be able to obtain additional financing on commercially reasonable terms or at all, or margins on our refined products will be favorable. Further, if Veritex exercises its rights and remedies under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.
Table of Contents
Management's Discussion and Analysis
Going Concern Management determined that certain factors raise substantial doubt about our ability to continue as a going concern. These factors include defaults under secured loan agreements, margin volatility, and historical net losses and working capital deficits, as discussed more fully below. Our consolidated financial statements assume we will continue as a going concern and do not include any adjustments that might result from this uncertainty. Our ability to continue as a going concern depends on sustained positive operating margins and adequate working capital for, amongst other requirements, purchasing crude oil and condensate and making payments on long-term debt. If we are unable to process crude oil and condensate into sellable refined products or make required debt payments, we may consider other options. These options might include selling assets, raising additional debt or equity capital, cutting costs, reducing cash requirements, restructuring debt obligations, or filing bankruptcy. Defaults Under Secured Loan Agreements. We are currently in default under certain of our secured loan agreements with third parties and related parties. See "Part I, Item 1. Financial Statements - Notes (1), (3), (10), and (11)" for additional disclosures related to third-party and related-party debt, defaults on such debt, and the potential effects of such defaults on our business, financial condition, and results of operations.
Third-Party Defaults
· Veritex Loans - For both three-month periods ended
2020, principal and interest payments to Veritex totaled
nine-months ended
payments to Veritex totaled
filing date of this report, LE and LRM were in default related to required
monthly payments under the LE Term Loan Due 2034 and LRM Term Loan Due 2034.
Defaults under the LE Term Loan Due 2034 and LRM Term Loan Due 2034 permit
Veritex to declare the amounts owed under these loan agreements immediately
due and payable, exercise its rights concerning collateral securing obligors'
obligations under these loan agreements, and exercise any other rights and
remedies available. Any exercise by Veritex of its rights and remedies under
these secured loan agreements would have a material adverse effect on our
business operations, including crude oil and condensate procurement and our
customer relationships; financial condition; and results of operations. These
adverse market actions could lead to holders of our common stock losing their
investment in its entirety. We cannot assure investors that: (i) our assets
or cash flow will be sufficient to repay borrowings under our secured loan
agreements with Veritex fully, either upon maturity or if accelerated, (ii)
LE and LRM will be able to refinance or restructure the payments of the debt,
or (iii) Veritex, as first lien holder, will provide future default waivers.
Borrowers and Veritex maintain ongoing dialogue regarding potential
restructuring and refinance opportunities related to this debt.
· Amended Pilot Line of Credit - On
owed to Pilot under the Amended Pilot Line of Credit. However, NPS was in
default as of
borrower or any guarantor to pay past-due obligations when due. The debt,
which accrued interest at a default rate of fourteen percent (14%) per annum,
was classified within the current portion of long-term debt on our
consolidated balance sheets at
Due to NPS' default under the Amended Pilot Line of Credit, Pilot applied
payments owed to NPS under two terminal services agreements against NPS'
payment obligations to Pilot under the Amended Pilot Line of Credit from June
2020 to
2021, and 2020, the tank lease payment setoff totaled
nine-month periods ended
setoff totaled
The amount of interest NPS incurred under the Amended Pilot Line of Credit
totaled
ended
2021, and 2020, interest was
"Part I, Item 1. Financial Statements - Note (11)" and "Note (17)" to our
consolidated financial statements for more information related to the Amended
Pilot Line of Credit.
· Kissick Debt - Under a 2015 subordination agreement,
subordinate his right to payments, as well as any security interest and liens
on the
LE Term Loan Due 2034. To date, LE has made no payments under the
subordinated Kissick Debt. Mr. Kissick has taken no action due to the
non-payment.
Related-Party Defaults
As of the filing date of this report, Blue Dolphin was in default concerning
past due payment obligations under the March Carroll Note, March Ingleside Note ,
and June LEH Note. As of the same date, BDPL was also in default related to past
due payment obligations under the BDPL-LEH Loan Agreement. Affiliates controlled
approximately 82% of the voting power of our Common Stock as of the filing date
of this report, an Affiliate operates and manages all Blue Dolphin properties,
an Affiliate is a significant customer of our refined products, and we borrow
from Affiliates during periods of working capital deficits.
Substantial Current Debt
As ofSeptember 30, 2021 , andDecember 31, 2020 , we had current debt of$58.4 million and$57.7 million , respectively, consisting of bank debt, related party debt, and the line of credit payable to Pilot, although the Pilot debt was subsequently repaid. Substantial current debt is primarily the result of secured loan agreements being in default. As a result, these debt obligations were classified within the current portion of long-term debt on our consolidated balance sheets atSeptember 30, 2021 , andDecember 31, 2020 .
Table of Contents
Management's Discussion and Analysis
Margin Volatility. Our refining margins generally improve in an environment of higher crude oil and refined product prices, and where the spread between crude oil prices and refined product prices widens. In early 2020, global and national measures taken to address the COVID-19 pandemic, including government-imposed temporary business closures and voluntary shelter-at-home directives, caused oil prices to decline sharply. In addition, actions by members ofOPEC and other producer countries in 2020 concerning oil production and pricing significantly impacted supply and demand in global oil and gas markets. With the introduction and approval of COVID-19 vaccines and increased inoculation rates, global economic activity has shown signs of recovery in 2021. Current EIA forecasts show economic growth and mobility increases in the short term. Also, refinery margins are forecasted to improve during the winter months due to projected colder winter temperatures compared to 2020 and low distillates inventory levels. However, forecasts are subject to various factors that are subject to change, including the ongoing impact of COVID-19 and related variants. As a result, we are currently unable to estimate our future financial position and results of operations. Accordingly, we believe these factors could have a material adverse effect on our financial results for the remainder of 2021
and into 2022.
Historic Net Losses and Working Capital Deficits.
Net Losses
Net loss for the three months endedSeptember 30, 2021 , was$2.9 million , or a loss of$0.23 per share, compared to a net loss of$4.7 million , or a loss of$0.37 per share, during the three months endedSeptember 30, 2020 . Net loss for the nine months endedSeptember 30, 2021 , was$10.2 million , or a loss of$0.80 per share, compared to a net loss of$12.2 million , or a loss of$0.98 per share, for the nine months endedSeptember 30, 2020 . The improvement between both comparative periods resulted from demand recovery, commodity price improvements, and encouraging trends in pandemic containment efforts.
Working Capital Deficits
We had$79.8 million and$72.3 million in working capital deficits atSeptember 30, 2021 , andDecember 31, 2020 , respectively. Excluding the current portion of long-term debt, we had$26.2 million and$22.6 million in working capital deficits atSeptember 30, 2021 , andDecember 31, 2020 , respectively. Cash and cash equivalents totaled$2.2 million and$0.5 million atSeptember 30, 2021 , andDecember 31, 2020 , respectively. Restricted cash (current portion) totaled$0.05 million at bothSeptember 30, 2021 , andDecember 31, 2020 . Restricted cash, noncurrent totaled$0 and$0.5 million atSeptember 30, 2021 , andDecember 31, 2020 , respectively. Our financial health has been materially and adversely affected by defaults in our secured loan agreements, margin volatility, and historical net losses and working capital deficits. If Pilot terminates the crude supply agreement or terminal services agreement, our ability to acquire crude oil and condensate could be adversely affected. If producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise, or we may not receive sufficient amounts to meet our needs. During the three-month periods endedSeptember 30, 2021 , and 2020, our refinery experienced 6 days and 8 days of downtime, respectively, due to crude deficiencies associated with COVID-19 related cash constraints. During the nine-month periods endedSeptember 30, 2021 , and 2020, our refinery experienced 11 days and 16 days of downtime, respectively. Operating Risks Successful execution of our business strategy depends on several critical factors, including having adequate working capital to meet contractual, operational, regulatory, and safety needs and having favorable margins on refined products. We are currently unable to estimate the impact the COVID-19 pandemic will have on our future financial position and results of operations. Earlier state and federal mandates that regulated business closures due to COVID-19 deemed our business essential, and we remained open. If future restrictive directives become necessary, we expect to continue operating. However, additional governmental mandates will likely result in business and operational disruptions, including demand destruction, liquidity strains, supply chain challenges, travel restrictions, controls on in-person gathering, and workforce availability. Management continues to take steps to mitigate risk, avoid business disruptions, manage cash flow, and remain competitive in a volatile commodity price environment. Mitigation steps include: adjusting throughput and production based on market conditions, optimizing receivables and payables by prioritizing payments, managing inventory to avoid buildup, monitoring discretionary spending, and delaying capital expenditures. To safeguard personnel, we adopted remote working where possible and social distancing, mask-wearing, and other site-specific precautionary measures where on-site operations are required. We also incentivize personnel to receive the COVID-19 vaccine. We can provide no guarantees that: our business strategy will be successful, Affiliates will continue to fund our working capital needs when we experience working capital deficits, we will meet regulatory requirements to provide additional financial assurance (supplemental pipeline bonds) and decommission offshore pipelines and platform assets, we will be able to obtain additional financing on commercially reasonable terms or at all, or margins on our refined products will be favorable. Further, if Veritex exercises its rights and remedies under our secured loan agreements, our business, financial condition, and results of operations will be materially adversely affected.
Table of Contents
Management's Discussion and Analysis
Business Strategy
Our primary business objective is to improve our financial profile by executing the below strategies, modified as necessary, to reflect changing economic conditions and other circumstances:
Optimize Existing • Operate safely and enhance
Asset Base health, safety, and
environmental systems.
• Planning and managing
turnarounds and downtime.
Improve Operational • Reduce or streamline variable
Efficiencies costs incurred in production.
• Increase throughput capacity
and optimize product slate.
• Increase tolling and
terminaling revenue.
Seize Market • Leverage existing
Opportunities infrastructure to engage in
renewable energy projects.
• Take advantage of market
opportunities as they arise.
Optimize Existing Asset Base. Throughout the third quarter of 2021, we
maintained safe and reliable operations at the Nixon facility. COVID-related
social distancing measures presented unique challenges. However, we successfully
balanced protecting personnel from exposure to COVID-19 and related variants and
ensuring adequate staffing levels to operate the plant. Refinery downtime
decreased to 6 days in the third quarter of 2021 compared to 11 days in the
third quarter of 2020.
Improve Operational Efficiencies. Refinery throughput, production, and sales
continued to improve year to date 2021 compared to 2020. Management process
reviews led to improved efficiencies in inventory management, throughput and
production levels, and cash management.
Seize Market Opportunities. We continue to explore renewable energy growth
opportunities through commercial partnerships and repurposing our assets and
facilities. In March 2021 , we announced a pivot to explore renewable energy
opportunities through an affiliate, Lazarus Energy Alternative Fuels LLC
("LEAF"). LEAF will explore potential options to position Blue Dolphin in the
global transition to cleaner, lower-carbon alternatives from traditional fossil
fuels through collaboration and innovation.
Successful execution of our business strategy depends on several factors. These
factors include (i) having adequate working capital to meet operational needs
and regulatory requirements, (ii) maintaining safe and reliable operations at
the Nixon facility, (iii) meeting contractual obligations, (iv) having favorable
margins on refined products, and (v) collaborating with new partners to develop
and finance clean energy projects. Our business strategy involves risks.
Accordingly, we cannot assure investors that our plans will be successful.
We regularly engage in discussions with third parties regarding possible joint
ventures, asset sales, mergers, and other potential business combinations.
However, we do not anticipate any material activities in the foreseeable future.
Management determined that conditions exist that raise substantial doubt about
our ability to continue as a going concern due to defaults under our secured
loan agreements, margin deterioration, and historical net losses and working
capital deficits. A 'going concern' opinion impairs our ability to finance our
operations by selling equity, incurring debt, or other financing alternatives.
Our ability to continue as a going concern depends on sustained positive
operating margins and working capital to sustain operations, purchase of crude
oil and condensate, and payments on long-term debt. If we cannot achieve these
goals, we may have to cease operating or seek bankruptcy protection.
Downstream Operations
Our refinery operations business segment consists of the following assets and
operations:
Key
Products Operating Location
Property Handled Subsidiary
Nixon facility Crude LE Nixon, Texas
• Crude distillation Oil
tower (15,000 bpd) Refined
• Petroleum storage Products
tanks
• Loading and
unloading facilities
• Land (56 acres)
Crude Oil and Condensate Supply. The operation of the Nixon refinery depends on
our ability to purchase adequate amounts of crude oil and condensate. We have a
long-term crude supply agreement in place with Pilot. The volume-based crude
supply agreement expires when Pilot sells us 24.8 million net bbls of crude oil.
After that, the crude supply agreement automatically renews for successive
one-year terms (each such term, a "Renewal Term"). Either party may provide the
other with notice of non-renewal at least 60 days before the expiration of any
Renewal Term. Effective June 30, 2020 , Pilot assigned its rights, title,
interest, and obligations in the crude supply agreement to Tartan Oil LLC , a
Pilot affiliate. As of September 30, 2021 , the total volume we received under
the crude supply agreement was approximately 7.9 million bbls.
Table of Contents
Management's Discussion and Analysis
Pilot also stores crude oil at theNixon facility under two terminal services agreements. Under the terminal services agreements, Pilot stores crude oil at theNixon facility at a specified rate per bbl of the storage tank's shell capacity. Although the initial term of the terminal services agreement expiredApril 30, 2020 , the agreement renews on a one-year evergreen basis. Either party may terminate the terminal services agreement by providing the other party 60 days prior written notice. However, the terminal services agreement will automatically terminate upon expiration or termination of the crude supply agreement. Our financial health has been materially and adversely affected by defaults in our secured loan agreements, margin volatility, and historical net losses and working capital deficits. If Pilot terminates the crude supply agreement or terminal services agreement, our ability to acquire crude oil and condensate could be adversely affected. If producers experience crude supply constraints and increased transportation costs, our crude acquisition costs may rise, or we may not receive sufficient amounts to meet our needs. During the three-month periods endedSeptember 30, 2021 , and 2020, our refinery experienced 6 days and 8 days of downtime, respectively, due to crude deficiencies associated with COVID-19 related cash constraints. During the nine-month periods endedSeptember 30, 2021 , and 2020, our refinery experienced 11 days and 16 days of downtime, respectively. Due to NPS' default under the Amended Pilot Line of Credit, Pilot applied payments owed to NPS under two terminal services agreements against NPS' payment obligations to Pilot under the Amended Pilot Line of Credit fromJune 2020 toSeptember 2021 . For both three-month periods endedSeptember 30, 2021 , and 2020, the tank lease payment setoff totaled$0.6 million . For the nine-month periods endedSeptember 30, 2021 , and 2020, the tank lease payment setoff totaled$1.7 million and$0.8 million , respectively. The amount of interest NPS incurred under the Amended Pilot Line of Credit totaled$0.2 million and$0.4 million , respectively, for the three months endedSeptember 30, 2021 , and 2020. For the nine months endedSeptember 30, 2021 , and 2020, interest was$0.7 million and$1.1 million , respectively. See "Part I, Item 1. Financial Statements - Note (1) Organization - Going Concern," "Note (11) Line of Credit Payable," and "Note (17) Subsequent Events" to our consolidated financial statements for additional disclosures related to the Amended Pilot Line of Credit. Products and Markets. Our market is theGulf Coast region of theU.S. , which the EIA represents asPetroleum Administration forDefense District 3 (PADD 3). We sell our products primarily in theU.S. within PADD 3. Occasionally, we sell refined products to customers that export toMexico .The Nixon refinery's product slate is moderately adjusted based on current market demand. We produce a single finished product - jet fuel - and several intermediate products, including naphtha, HOBM, and AGO. We sell our jet fuel to an Affiliate, which is HUBZone certified. The product sales agreement with the Affiliate has a 1-year term expiring the earliest to occur ofMarch 31, 2022 , plus 30-day carryover or delivery of the maximum quantity of jet fuel. Our intermediate products are primarily sold in nearby markets to wholesalers and refiners as a feedstock for further blending and processing. Customers. Customers for our refined products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (theHouston -San Antonio -Dallas/Fort Worth area). We have bulk term contracts in place with most of our customers, including month-to-month, six months, and up to one-year terms. Certain of our contracts require customer prepayments and the sale of fixed or minimum quantities of finished and intermediate petroleum products. Many of these arrangements are subject to periodic renegotiation on a forward-looking basis, which could result in higher or lower relative prices on future sales of our refined products. Competition. Many of our competitors are substantially larger than us. Their size and greater access to resources allow them to engage in various oil and gas industry segments on a national or international level. These competitors may have greater flexibility in responding to or absorbing market changes occurring in one or more of these business segments. We compete primarily based on cost. Due to the low complexity of our simple "topping unit" refinery, we can be relatively nimble in adjusting our refined products slate because of changing commodity prices, market demand, and refinery operating costs. Safety and Downtime. We operate our refinery in a way materially consistent with industry safety practices and standards.EPA ,OSHA , and comparable state and local regulatory agencies provide oversight for personnel safety, process safety management, and risk management to prevent or minimize the accidental release of toxic, reactive, flammable, or explosive chemicals. Technological systems enhance regulatory oversight. For example, most of our storage tanks have emissions control devices. We also have response and control plans in place for spill prevention and emergencies.The Nixon refinery periodically experiences planned and unplanned temporary shutdowns. We use planned turnarounds to repair, restore, refurbish, or replace refinery equipment. Unplanned shutdowns occur for various reasons, including voluntary regulatory compliance measures, cessation or suspension by regulatory authorities, disabled equipment, or crude deficiencies due to cash constraints. However, the most typical reason is excessive heat or power outages from high winds and thunderstorms inTexas .The Nixon refinery did not incur significant damage due to Winter Storm Uri in the first quarter of 2021. However, the facility lost external power for 10 days. We are particularly vulnerable to operation disruptions because all our refining operations occur at a single facility. Any scheduled or unscheduled downtime results in lost margin opportunity, reduced refined products inventory, and potential increased maintenance expense, all of which could reduce our ability to meet our payment obligations.
Table of Contents
Management's Discussion and Analysis
Midstream Operations
Our tolling and terminaling business segment consists of the following assets
and operations:
Key
Products Operating Location
Property Handled Subsidiary
Nixon facility Crude LRM, NPS Nixon, Texas
• Petroleum storage Oil
tanks Refined
• Loading and unloading Products
facilities
Products and Customers. The Nixon facility's petroleum storage tanks and
infrastructure are primarily suited for crude oil and condensate and refined
products, such as naphtha, jet fuel, diesel, and fuel oil. Storage customers are
typically refiners in the lower portion of the Texas Triangle (the Houston - San
Antonio - Dallas/Fort Worth area). Shipments are received and redelivered from
within the Nixon facility via pipeline or from third parties via truck. Contract
terms range from month to month to three years.
Operations Safety. We conduct our midstream operations in a manner materially
consistent with industry safety practices and standards. EPA , OSHA , and
comparable state and local agencies provide regulatory oversight. We have the
appropriate emergency response and spill prevention and control plans in place.
Inactive Operations
We own other pipeline and facilities assets and have leasehold interests in oil and gas properties. These assets are not operational. We account for these inactive operations in 'corporate and other.' We fully impaired our pipeline assets in 2016 and our oil and gas leasehold interests in 2011. Our pipeline assets and oil and gas leasehold interests had no revenue during the three and nine months endedSeptember 30, 2021 , and 2020. See "Part I, Item 1. Financial Statements - Note (16)" related to abandonment requirements and associated
risks.
Operating
Property Subsidiary Location
Freeport facility BDPL Freeport,
• Crude oil and natural gas Texas
separation and dehydration
• Natural gas processing,
treating, and redelivery
• Vapor recovery unit
• Two onshore pipelines
• Land (162 acres)
Offshore Pipelines (Trunk BDPL Gulf of
Line and Lateral Lines) Mexico
Oil and Gas Leasehold BDPC Gulf of
Interests Mexico
Pipeline and Facilities Safety.
Although our pipeline and facility assets are inactive, they require upkeep and maintenance. They are also subject to safety requirements under PHMSA, BOEM, BSEE, and comparable state and local regulations. We have response and control plans, spill prevention, and other programs to respond to emergencies related to these assets. Results of Operations We present below a discussion and analysis of the factors contributing to our consolidated financial results of operations. Investors should read this section in conjunction with our financial statements in "Part I, Item 1. Financial Statements". When combined with the following information, the financial statements provide investors with a reasonable basis for assessing our historical operations. However, this information should not serve as the only criteria for predicting our future performance. Major Influences on Results of Operations. Our results of operations and liquidity depend on the margins that we receive for our refined products. The dollar per bbl price difference between crude oil and condensate (input) and refined products (output) significantly drives refining margins. These margins have historically been subject to wide fluctuations. In early 2020, global and national measures taken to address the COVID-19 pandemic, including government-imposed temporary business closures and voluntary shelter-at-home directives, caused oil prices to decline sharply. In addition, actions by members ofOPEC and other producer countries in 2020 concerning oil production and pricing significantly impacted supply and demand in global oil and gas markets. With the introduction and approval of COVID-19 vaccines and increased inoculation rates, global economic activity has shown signs of recovery in 2021. Current EIA forecasts show economic growth and mobility increases in the short term. Also, refinery margins are forecasted to improve during the winter months due to projected colder winter temperatures compared to 2020 and low distillates inventory levels. However, forecasts are subject to various factors that are subject to change, including the ongoing impact of COVID-19 and related variants. As a result, we are currently unable to estimate our future financial position and results of operations. Accordingly, we believe these factors could have a material adverse effect on our financial results for the remainder of 2021 and into 2022.
Table of Contents
Management's Discussion and Analysis
How We Evaluate Our Operations. Management uses particular financial and operating measures to analyze business segment performance. These measures are significant factors in assessing our operating results and profitability and include: segment contribution margin (deficit), refining gross profit (deficit) per bbl, tank rental revenue, operation costs and expenses, refinery throughput and production data, and refinery downtime. Segment contribution margin (deficit) and refining gross profit (deficit) per bbl are non-GAAP measures.
Segment Contribution Margin (Deficit) and Refining Gross Profit (Deficit) per Bbl
We use segment contribution margin (deficit) to evaluate the performance of our downstream and midstream operations. We use refining gross profit (deficit) per bbl as a downstream benchmark. Both measures supplement GAAP financial information presented. Management uses segment contribution margin (deficit) and refining gross profit (deficit) per bbl to analyze our results of operations, assess internal performance against budgeted and forecasted amounts, and evaluate impacts to our financial performance considering potential capital investments. These non-GAAP measures have important limitations as analytical tools. They should not be considered a substitute for GAAP financial measures. We believe these measures may help investors, analysts, lenders, and ratings agencies analyze our results of operations and liquidity in conjunction with our GAAP financial results. See the "Glossary of Terms" for information on how to calculate these non-GAAP measures. See also "Results of Operations - Non-GAAP Reconciliations" within this section and "Part I, Item 1. Financial Statements" for a reconciliation of these Non-GAAP measures to GAAP.
Tank Rental Revenue
Tolling and terminaling revenue primarily represents tank rental storage fees associated with customer tank rental agreements. As a result, management uses tank rental revenue to evaluate the performance of our tolling and terminaling business segment. Operation Costs and Expenses Operation costs and expenses include cost of goods sold. Also, operation costs and expenses within: (i) the tolling and terminaling business segment includes terminal operating expenses and an allocation of other costs (e.g., insurance and maintenance) and (ii) corporate and other includes expenses related to
BDSC, BDPC, and BDPL.
Refinery Throughput and Production Data
Our refinery operations revenue depends on crude oil throughput volumes, refined products production volumes, and customer sales volumes. The supply and demand of, and demand for, crude oil and refined products in the markets served directly or indirectly by our assets, as well as refinery downtime affect these volumes. Refinery Downtime
Remainder of Page Intentionally Left Blank
Table of Contents
Management's Discussion and Analysis
Consolidated Results. Our consolidated results of operations include certain unallocated corporate activities and the elimination of intercompany transactions. Therefore, the sum of operating results for our 'refinery operations' business segment and 'tolling and terminaling' business segment do not equal consolidated results of operations. Three Months EndedSeptember 30, 2021 Nine Months EndedSeptember 30, 2021 VersusSeptember 30, 2020 (Q3 2021 VersusSeptember 30, 2020 (9 Months 2021 Versus Q3 2020) Versus 9 Months 2020) Overview. Net loss for Q3 2021 was$2.9 Overview. Net loss for 9 Months 2021 was million, or a loss of$0.23 per share,$10.2 million , or a loss of$0.80 per compared to a net loss of$4.7 million , share, compared to a net loss of$12.2 or a loss of$0.37 per share, in Q3 million, or a loss of$0.98 per share, 2020. The improvement between the in 9 Months 2020. The improvement periods resulted from a slight recovery between the periods resulted from a in market conditions as more businesses slight recovery in market conditions as resumed operations and pandemic-related more businesses resumed operations and restrictions lifted. Commodity prices pandemic-related restrictions lifted. were more favorable, and our throughput Commodity prices were more favorable, and sales volumes improved. Less and our throughput and sales volumes refinery downtime also contributed to improved. Less refinery downtime and the improvement between the periods. decreased interest and other expense also contributed to the
improvement
between the periods.
Total Revenue from Operations. Total Total Revenue from Operations. Total
revenue from operations increased revenue from operations increased
significantly in Q3 2021 to $80.4 significantly in 9 Months 2021 to $209.2
million compared to $42.9 million in Q3 million compared to $123.4 million in 9
2020. The increase between the periods Months 2020. The increase between the
related to higher refined product periods related to higher refined
prices, sales volume, and ancillary product prices, sales volume, and
service fees (tank blending, lab ancillary service fees. The increase was
testing, etc.). The increase was offset offset by lower tank rental revenue.
by lower tank rental revenue.
Total Cost of Goods Sold. Total cost of Total Cost of Goods Sold. Total cost of
goods sold increased significantly in Q3 goods sold increased significantly in 9
2021 to $80.1 million compared to $44.4 Months 2021 to $210.2 million compared
million for Q3 2020. The increase in Q3 to $126.2 million for 9 Months 2020. The
2021 related to higher crude oil costs increase in 9 Months 2021 related to
and increased throughput volume higher crude oil costs and increased
associated with improved refined product throughput volume associated with
demand from economy recovery. improved refined product demand from
economy recovery.
Gross Profit. Gross profit was $0.3 Gross Deficit. Gross deficit improved
million for Q3 2021 compared to a gross significantly in 9 Months 2021 to $1.0
deficit of $1.5 million for Q3 2020. The million compared to $2.8 million for 9
significant improvement resulted from Months 2020. The significant improvement
more stable commodity prices and resulted from more stable commodity
improved sales volumes from economic prices and improved sales volumes from
recovery. economic recovery.
General and Administrative Expenses. General and Administrative Expenses.
General and administrative expenses were General and administrative expenses were
relatively flat at $0.7 million for both relatively flat at $1.9 million for both
Q3 2021 and Q3 2020 due to cost 9 Months 2021 and 9 Months 2020 due to
management efforts. cost management efforts.
Depletion, Depreciation, and Depletion, Depreciation, and
Amortization. Depletion, depreciation, Amortization. Depletion, depreciation,
and amortization expenses were flat at and amortization expenses totaled $2.1
$0.7 million for Q3 2021 and Q3 2020. million for 9 Months 2021 compared to
Depletion, depreciation, and $2.0 million for 9 Months 2020,
amortization expense primarily related representing an increase of
to refinery assets. approximately $0.1 million . The increase
related to placing refinery assets in
service.
Total Other Expense. Total other expenseTotal Other Expense. Total other expense was$4.7 million in 9 Months 2021 increased slightly in Q3 2021 to$1.7 compared to$4.9 million in 9 Months million compared to$1.6 million in Q3 2020, representing a decrease of 2020. The increase primarily related to approximately$0.2 million . The decrease higher related-party interest expense. primarily related to lower Pilot Total other expense in both periods interest expense. Total other expense in primarily related to interest expense both periods primarily related to associated with secured loan agreements interest expense associated with secured with Veritex, related-party debt, and loan agreements with Veritex, the line of credit with Pilot. related-party debt, and the line of credit with Pilot.
Table of Contents
Management's Discussion and Analysis
Downstream Operations. LE owns our refinery operations business segment. Assets within this segment consist of a light sweet-crude, 15,000-bpd crude distillation tower, petroleum storage tanks, loading and unloading facilities, and approximately 56 acres of land. LE derives refinery operations revenue
from
refined product sales.
Three Months Ended
September 30,
2021 2020
(in thousands)
Refined product sales $ 79,466 $ 41,929
Less: Total cost of goods sold (80,114 ) (44,400 )
Gross deficit (648 ) (2,471 )
Sales (Bbls) 1,059 1,008
Gross Deficit per Bbl $ (0.61 ) $ (2.45 )
Three Months Ended
September 30,
2021 2020
(in thousands)
Net revenue (1) $ 79,466 $ 41,929
Intercompany fees and sales (650 ) (595 )
Operation costs and expenses (79,593 ) (43,691 )
Segment Contribution Deficit $ (777 ) $ (2,357 ) (1) Net revenue excludes intercompany crude sales.
Q3 2021 Versus Q3 2020
· Refining gross deficit per bbl was
deficit per bbl of
bbl. The improvement between the periods related to higher refining margins;
sales volume was relatively flat. Commodity prices and refined product demand
experienced a recovery in Q3 2021 compared to Q3 2020 as more businesses
resumed operations and pandemic-related restrictions lifted.
· Segment contribution deficit improved significantly in Q3 2021 compared to Q3
2020 due to the aforementioned economic recovery and less refinery downtime.
· Refinery downtime decreased to 6 days in Q3 2021 compared to 11 days in Q3
2020. Refinery downtime in Q3 2021 related to crude deficiencies associated
with cash constraints. Refinery downtime in Q3 2020 was due to crude
deficiencies associated with cash constraints and equipment repairs.
Nine Months Ended
September 30,
2021 2020
(in thousands)
Refined product sales $ 206,467 $ 120,185
Less: Total cost of goods sold (210,203 ) (126,164 )
Gross deficit (3,736 ) (5,979 )
Sales (Bbls) 2,995 2,818
Gross Deficit per Bbl $ (1.25 ) $ (2.12 )
Nine Months Ended
September 30,
2021 2020
(in thousands)
Net revenue (1) $ 206,467 $ 120,185
Intercompany fees and sales (1,797 ) (1,618 )
Operation costs and expenses (208,936 ) (124,942 )
Segment Contribution Deficit $ (4,266 ) $ (6,375 ) (1) Net revenue excludes intercompany crude sales.
9 Months 2021 Versus 9 Months 2020
· Refining gross deficit per bbl was
deficit per bbl of
margins and slightly higher sales volume. Commodity prices and refined
product demand experienced a recovery in 9 Months 2021 compared to 9 Months
2020 as more businesses resumed operations and pandemic-related restrictions
lifted. For 9 Months 2021, the impact of Winter Storm Uri offset the economic
recovery.
· Segment contribution deficit improved significantly in 9 Months 2021 compared
to 9 Months 2020 due to the above referenced economic recovery. However, the
impact of Winter Storm Uri offset the economic recovery.
· Refinery downtime decreased to 21 days in 9 Months 2021 compared to 37 days
in 9 Months 2020. Two material events triggered significant refinery downtime
in 9 Months 2021 compared to 9 Months 2020: (i) power outages from Winter
Storm Uri and (ii) COVID-19-related shutdowns and market upheavals. The
extensive shutdown period resulted in cash constraints that further impacted
the acquisition of crude oil. During the 9 Months 2020, we capitalized on
downtime to perform a maintenance turnaround.
Table of Contents
Management's Discussion and Analysis
Midstream Operations. LRM and NPS own our tolling and terminaling business
segment. Assets within this segment include petroleum storage tanks and loading
and unloading facilities. LRM and NPS derive tolling and terminaling revenue
from tank storage rental fees, tolling and reservation fees for use of the
naphtha stabilizer, and fees collected for ancillary services, such as in-tank
blending.
Three Months Ended
September 30,
2021 2020
(in thousands)
Net revenue (1) $ 924 $ 1,001
Intercompany fees and sales 650 595
Operation costs and expenses (521 ) (709 )
Segment Contribution Margin $ 1,053 $ 887 (1) Net revenue excludes intercompany crude sales.
Q3 2021 Versus Q3 2020
· Tolling and terminaling net revenue decreased nearly 8% in Q3 2021 compared
to Q3 2020 primarily as a result of lower tank rental fees.
· Intercompany fees and sales, which reflect fees associated with an
intercompany tolling agreement tied to naphtha volumes, increased in Q3 2021
compared to Q3 2020. Naphtha sales volumes increased between the periods as a
result of demand recovery.
· Segment contribution margin in Q3 2021 increased nearly 19% to
compared to
margin related to lower operation costs and expenses.
Nine Months Ended
September 30,
2021 2020
(in thousands)
Net revenue (1) $ 2,777 $ 3,214
Intercompany fees and sales 1,797 1,618
Operation costs and expenses (1,267 ) (1,222 )
Segment Contribution Margin $ 3,307 $ 3,610 (1) Net revenue excludes intercompany crude sales.
9 Months 2021 Versus 9 Months 2020
· Tolling and terminaling net revenue decreased nearly 14% in 9 Months 2021
compared to 9 Months 2020 due to lower tank rental fees.
· Intercompany fees and sales, which reflect fees associated with an
intercompany tolling agreement tied to naphtha volumes, increased in 9 Months
2021 compared to 9 Months 2020. Naphtha sales volumes increased between the
periods as a result of demand recovery.
· Segment contribution margin in 9 Months 2021 decreased 8% to
compared to $3.6 million in 9 Months 2020. The decrease in segment
contribution margin related to lower revenue.
Table of Contents
Management's Discussion and Analysis
Non-GAAP Reconciliations.
Reconciliation of Segment Contribution Margin (Deficit)
Three Months Ended September 30,
2021 2020 2021 2020 2021 2020 2021 2020
Refinery Operations Tolling and Terminaling Corporate and Other Total
(in thousands)
Segment
contribution
margin
(deficit) $ (777 ) $ (2,357 ) $ 1,053 $ 887 $ (83 ) $ (58 ) $ 193 $ (1,528 )
General and
administrative
expenses(1) (282 ) (414 ) (70 ) (132 ) (423 ) (307 ) (775 ) (853 )
Depreciation
and
amortization (302 ) (301 ) (340 ) (338 ) (51 ) (51 ) (693 ) (690 ) Interest and other non-operating expenses, net (747 ) (679 ) (384 ) (599 ) (523 ) (304 ) (1,654 ) (1,582 ) Income (loss) before income taxes (2,108 ) (3,751 ) 259 (182 ) (1,080 ) (720 ) (2,929 ) (4,653 ) Income tax expense - - - - - - - -
Income (loss)
(1) General and administrative expenses within refinery operations include the
LEH operating fee.
Nine Months Ended September 30,
2021 2020 2021 2020 2021 2020 2021 2020
Refinery Operations Tolling and Terminaling Corporate and Other Total
(in thousands)
Segment
contribution
margin
(deficit)
$ (187 ) $ (164 ) $ (1,146 ) $ (2,929 ) General and administrative expenses(1) (848 ) (1,045 ) (206 ) (268 ) (1,246 ) (1,052 ) (2,300 ) (2,365 ) Depreciation and amortization (906 ) (883 ) (1,020 ) (956 ) (153 ) (153 ) (2,079 ) (1,992 ) Interest and other non-operating expenses, net (2,053 ) (2,171 ) (1,284 ) (1,985 ) (1,340 ) (778 ) (4,677 ) (4,934 ) Income (loss) before income taxes (8,073 ) (10,474 ) 797 401
(2,926 ) (2,147 ) (10,202 ) (12,220 ) Income tax expense
- - - - - (15 ) - (15 )
Income (loss)
$ (2,926 ) $ (2,162 ) $ (10,202 ) $ (12,235 )
(1) General and administrative expenses within refinery operations include the LEH operating fee.
Liquidity and Capital Resources
We had$79.8 million and$72.3 million in working capital deficits atSeptember 30, 2021 , andDecember 31, 2020 , respectively. Excluding the current portion of long-term debt, we had working capital deficits of$26.2 million and$22.6 million atSeptember 30, 2021 , andDecember 31, 2020 , respectively. During the third quarter of 2021, we continued efforts to conserve cash amid lower refined product sales. Mitigation steps include: adjusting throughput and production based on market conditions, optimizing receivables and payables by prioritizing payments, managing inventory to avoid buildup, delaying capital spending, and monitoring discretionary spending and nonessential costs. Our primary cash requirements relate to: (i) purchasing crude oil and condensate for the operation of theNixon refinery , (ii) reimbursing LEH for direct operating expenses and paying the LEH operating fee under the Amended and Restated Operating Agreement and (iii) servicing debt. Due to the adverse financial impact of COVID-19, we are actively exploring financing, including potential financing options made available under the Coronavirus Aid, Relief, and Economic Security Act, also known as the CARES Act. However, we cannot assure success in raising additional capital or that such additional funds will be available on acceptable terms, if at all. We may further default on certain of our existing debt obligations if we cannot raise sufficient additional capital in the very near term. Without additional financing, it remains unclear whether we will have or can obtain sufficient liquidity to withstand further disruptions to our business. How long and to what extent COVID-19 and related market developments will continue to affect our business and operations is unknown. With the introduction and approval of COVID-19 vaccines and increased inoculation rates, global economic activity has shown signs of recovery in 2021. Current EIA forecasts show economic growth and mobility increases in the short term. Also, refinery margins are forecasted to improve during the winter months due to projected colder winter temperatures compared to 2020 and low distillates inventory levels. However, forecasts are subject to various factors that are subject to change, including the ongoing impact of COVID-19 and related variants. As a result, we are currently unable to estimate our future financial position and results of operations. Accordingly, we believe these factors could have a material adverse effect on our financial results for the remainder of 2021
and into 2022. Our ability to continue as a going concern depends on sustained positive operating margins and working capital to sustain operations, purchase of crude oil and condensate, and payments on long-term debt. If we cannot achieve these goals, we may cease operating or seek bankruptcy protection. These adverse market actions could lead to holders of our common stock losing their investment in its entirety.
Table of Contents
Management's Discussion and Analysis
Debt Overview.
Total Debt and Accrued Interest
September 30 ,December 31, 2021 2020 (in thousands) Veritex Loans
LE Term Loan Due 2034 (in default)$ 23,827 $
22,840
LRM Term Loan Due 2034 (in default) 9,881
9,473
Kissick Debt (in default) 10,011
9,413
Amended Pilot Line of Credit (in default) 4,827
8,145
Related-Party Debt June LEH Note (in default) 12,644
9,446
BDPL Loan Agreement (in default) 7,294
6,814
March Carroll Note (in default) 2,115
1,551
March Ingleside Note (in default) 1,059
1,013 BDEC Term Loan Due 2051 507 - LE Term Loan Due 2050 155 152 NPS Term Loan Due 2050 155 152 Equipment Loan Due 2025 59 71
Total debt and accrued interest 72,534
69,070
Less: Current portion of long-term debt, net (58,360 ) (57,744 ) Less: Unamortized debt issue costs (1,653 ) (1,749 ) Less: Accrued interest payable (in default) (11,678 ) (9,222 ) Long-term debt, net of current portion $ 843 $
355
Due to cash constraints associated with COVID-19, payments on debt in 2021 were minimal totaling$0.004 million in Q3 2021 and$0.013 million in 9 Months 2021. Comparatively, payments on debt in 2020 totaled$0.9 million in Q3 2020 and$2.4 million in 9 Months 2020. We received government assistance from CARES Act loans in both 2021 and 2020. For 9 Months 2021, proceeds from issuance of debt totaled$0.5 million compared to$0.3 million in 9 Months 2020. In 9 Months 2021, we received a single SBA EIDL loan; in 9 Months 2020 we received two smaller SBA EIDL loans. Debt Defaults. The majority of our debt is in default. Defaults under Veritex loans include financial covenant violations, failure to make monthly payments, and failure to replenish a payment reserve account. As the Kissick Debt and related-party debts have matured, defaults are for failure to pay past due obligations. OnOctober 4, 2021 , NPS repaid all obligations owed to Pilot under the Amended Pilot Line of Credit. However, NPS was in default as ofSeptember 30, 2021 , andDecember 31, 2020 . Due to their default status, we classified all of these debts within the current portion of long-term debt on our consolidated balance sheets atSeptember 30, 2021 , andDecember 31, 2020 . See "Part I, Item 1. Financial Statements - Notes (1), (3), (10), (11), and (17)" for additional disclosures related to Affiliate and third-party debt agreements, including debt guarantees, and defaults in our debt obligations. Contractual Obligations. Related-Party Debt Agreement/Transaction Parties Type Effective Date Interest Rate Key Terms Amended and Restated Jonathan Debt 04/01/2017 2.00% Tied to payoff of LE Guaranty Fee Agreement Carroll$25 million Veritex LE loan; payments 50% cash, 50% Common Stock Amended and Restated Jonathan Debt 04/01/2017 2.00% Tied to payoff of LRM Guaranty Fee Agreement Carroll$10 million Veritex LRM loan; payments 50% cash, 50% Common Stock March Carroll Note (in Jonathan Debt 03/31/2017 8.00% Blue Dolphin working default) Carroll capital; matured Blue 01/01/2019; reflects Dolphin amounts owed to Jonathan Carroll under guaranty fee agreements; interest still accruing March Ingleside Note Ingleside Debt 03/31/2017 8.00% Blue Dolphin working (in default) Blue capital; matured Dolphin 01/01/2019; interest still accruing June LEH Note (in LEH Debt 03/31/2017 8.00% Blue Dolphin working default) Blue capital; reflects Dolphin amounts owed to LEH under the Amended and Restated Operating Agreement; matured 01/01/2019; interest still accruing
BDPL-LEH Loan LEH Debt 08/15/2016 16.00% 2-year term;$4.0 Agreement (in default) BDPL million
principal
amount; $0.5 million
annual payment;
proceeds used for
working capital; no
financial maintenance
covenants; secured by
certain BDPL property
Table of Contents
Management's Discussion and Analysis
Related-Party Defaults
Loan Description Event(s) of Default Covenant Violations
March Carroll Note Failure of borrower to pay past due --
(in default) payment obligations; loan matured
January 2019
March Ingleside Note Failure of borrower to pay past due ---
(in default) payment obligations; loan matured
January 2019
June LEH Note (in Failure of borrower to pay past due ---
default) payment obligations; loan matured
January 2019
BDPL-LEH Loan Failure of borrower to pay past due ---
Agreement (in payment obligations; loan matured
default) August 2018
Third-Party Debt
Original
Principal Monthly
Amount Maturity Date Principal
Loan Description Parties (in and Interest Interest Loan Purpose
millions) Payment Rate
Veritex Loans(1)
LE Term Loan Due LE $25.0 Jun 2034 $0.2 million WSJ Prime Refinance
2034 (in default) Veritex + 2.75% loan; capital
improvements
LRM Term Loan Due LRM $10.0 Dec 2034 $0.1 million WSJ Prime Refinance
2034 (in default) Veritex + 2.75% bridge loan;
capital
improvements
Kissick Debt (in LE $11.7 Jan 2018 No payments 16.00% Working
default)(2)(3) Kissick to date; capital;
payment reduced
rights balance of GEL
subordinated arbitration
award
Amended Pilot Line NPS $13.0 May 2020 --- 14.00% GEL settlement
of Credit (in Pilot payment, NPS
default) purchase of
crude oil from
Pilot, and
working
capital
SBA EIDLsBDEC Term Loan Due Blue Dolphin$0.5 Jun 2051$0.003 3.75%
Working
2051(4) SBA million capital
LE Term Loan Due LE $0.15 Aug 2050 $0.0007 3.75% Working
2050(5) SBA million capital
NPS Term Loan Due NPS $0.15 Aug 2050 $0.0007 3.75% Working
2050(5) SBA million capital
Equipment Loan Due LE $0.07 Oct 2025 $0.0013 4.50% Equipment
2025(6) Texas First million Lease
Conversion
(1) Veritex placed proceeds in a disbursement for the payment of
construction-related expenses. We reflected the amounts held in the disbursement
account as restricted cash (current portion) and restricted cash, noncurrent on
our consolidated balance sheets. At September 30, 2021 , restricted cash (current
portion) was $0.05 million and restricted cash, noncurrent was $0 . At December
31, 2020 , restricted cash (current portion) was $0.05 million and restricted
cash, noncurrent was $0.5 million .
(2) LE originally entered into a loan agreement with Notre Dame Investors, Inc.
in the principal amount of $8.0 million . John Kissick currently holds this debt.
Under a 2017 amendment, the parties amended the Kissick Debt to increase the
principal amount by $3.7 million . LE used the additional principal to reduce the
arbitration award payable to GEL by $3.6 million .
(3) Under a 2015 subordination agreement, John Kissick agreed to subordinate his
right to payments, as well as any security interest and liens on the Nixon
facility's business assets, in favor of Veritex as holder of the LE Term Loan
Due 2034.
(4) For disaster loans made in 2021, the SBA initially deferred payments for the
first twelve (12) months. The SBA later extended the payment deferral period
from twelve (12) months to eighteen (18) months; under the extension, the first
payment is due in December 2022 ; interest accrues during the deferral period.
The BDEC Term Loan Due 2051 is not forgivable.
(5) For disaster loans made in 2020, the SBA initially deferred payments for the
first twelve (12) months. The SBA later extended the payment deferral period
from twelve (12) months to twenty-four (24) months; under the extension, the
first payment is due in September 2022 ; interest accrues during the deferral
period. The LE Term Loan Due 2050 and NPS Term Loan Due 2050 are not forgivable.
(6) In May 2019 , LE entered into a 12-month equipment rental agreement with the
option to purchase the backhoe at maturity. The equipment rental agreement
matured in May 2020 . In October 2020 , LE entered into the Equipment Loan Due
2025 to finance the backhoe purchase. We use the backhoe at the Nixon facility.
Third-Party Defaults
Loan Description Event(s) of Default Covenant Violations
Veritex Loans
LE Term Loan Due Failure to make Financial covenants:
2034 (in default) required monthly • debt service coverage ratio,
payments; failure to current ratio, and debt to net
replenish $1.0 million worth ratio
payment reserve
account; events of
default under other
secured loan
agreements with
VeritexLRM Term Loan Due Events of default Financial covenants: 2034 (in default) under other secured • debt service coverage ratio,
loan agreements with current ratio, and debt to net
Veritex worth ratio
Amended Pilot Line Failure of borrower or ---
of Credit (in any guarantor to pay
default) past due obligations;
loan matured May 2020
Kissick Debt (in Failure of borrower to ---
default) pay past due
obligations; loan
matured January 2019 Table of Contents
Management's Discussion and Analysis
Concentration of Customers Risk. We routinely assess the financial strength of
our customers. To date, we have not experienced significant write-downs in
accounts receivable balances. We believe that our accounts receivable credit
risk exposure is limited.
Portion of
Accounts
% Total Receivable
Number Significant Revenue from at September
Three Months Ended Customers Operations 30,
September 30, 2021 3 69 % $ 0
September 30, 2020 4 80 % $ 0
One of our significant customers is LEH, an Affiliate. Due to a HUBZone
certification, the Affiliate purchases our jet fuel under a Jet Fuel Sales
Agreement and bids on jet fuel contracts under preferential pricing terms. The
Affiliate accounted for 30% and 28% of total revenue from operations for the
three months ended September 30, 2021 , and 2020, respectively. The Affiliate
represented $0 in accounts receivable at both September 30, 2021 , and 2020,
respectively.
Portion of
Accounts
% Total Receivable
Number Significant Revenue from at September
Nine Months Ended Customers Operations 30,
September 30, 2021 3 72 % $ 0
September 30, 2020 4 82 % $ 0
The Affiliate accounted for 29% and 28% of total revenue from operations for the
nine months ended
Outstanding amounts under certain related party agreements can significantly vary from period to period based on the timing of sales and payments. Concerning the Amended and Restated Operating Agreement, we add any amount that remains outstanding at the end of the quarter to the June LEH Note. We classify the June LEH Note within long-term debt, related party, current portion (in default) on the consolidated balance sheets. AtSeptember 30, 2021 , andDecember 31, 2020 , the total amount we owed to LEH under long-term debt, related-party agreements including accrued interest totaled$19.9 million and$16.3 million , respectively. See "Part I, Item 1. Financial Statements - Notes (3) and (16)" for additional disclosures related to Affiliate agreements, arrangements, and risk.
BOEM Additional Financial Assurance (Supplemental Pipeline Bonds)
Offshore lessees, operators, and rights-of-way holders are required to provide BOEM with the financial assurance of their ability to carry out present and future abandonment obligations. Obligations include the cost of plugging and abandoning wells and decommissioning pipelines and platforms at the end of production or service activities. When the lessee, operator, or rights-of-way holder completes abandonment work, BOEM releases the collateral backing the financial assurance. InMarch 2018 , BOEM ordered BDPL to provide additional financial assurance totaling approximately$4.8 million for five (5) existing pipeline rights-of-way. BDPL historically maintained$0.9 million in financial security. InJune 2018 , BOEM issued BDPL INCs for each right-of-way that failed to comply. BDPL appealed the INCs to the IBLA. Because the IBLA is separate and independent from the agencies whose decisions it reviews, BDPL's appeal to BOEM took considerable time to matriculate through the appeals process. Ultimately, theOffice of the Solicitor of the U.S. Department of the Interior signaled that, once BDPL completes abandonment operations, the amount of financial assurance required by BOEM will be significantly reduced or eliminated. In addition, BOEM's INCs will be partially or fully resolved. Although we planned decommissioning activities for 2020, offshore weather conditions and cash constraints associated with the ongoing COVID-19 pandemic led to delays. We cannot currently estimate when decommissioning will occur. Further, we cannot currently estimate when we can provide additional financial assurance (supplemental pipeline bonds). Financial constraints and BDPL's pending appeal of the BOEM INCs do not relieve BDPL of its obligations to provide additional financial assurance or of BOEM's authority to impose financial penalties. If BOEM requires BDPL to provide significant additional financial security or assesses significant penalties under the INCs, we will experience a significant and material adverse effect on our operations, liquidity, and financial condition. We are currently unable to predict the outcome of the BOEM INCs. Accordingly, we have not recorded a liability on our consolidated balance sheet as ofSeptember 30, 2021 . At bothSeptember 30, 2021 , andDecember 31, 2020 , BDPL maintained approximately$0.9 million in credit and cash-backed pipeline rights-of-way
bonds issued to BOEM.
Table of Contents
Management's Discussion and Analysis
BSEE Offshore Pipelines and Platform Decommissioning
BDPL has pipelines and platform assets that are subject to BSEE's idle iron regulations. Idle iron regulations mandate lessees and rights-of-way holders to permanently abandon or remove platforms and other structures when they are no longer active. Until such facilities are decommissioned, lessees and rights-of-way holders must inspect and maintain them per regulatory requirements. InDecember 2018 , BSEE issued an INC to BDPL for failure to flush and fill Pipeline Segment No. 13101. Management met with BSEE inAugust 2019 to address BDPL's plans concerning decommissioning its offshore pipelines and platform assets. BSEE proposed BDPL re-submit permit applications for pipeline and platform decommissioning and a safe boarding plan for the platform. BSEE imposed a deadline of six (6) months (February 2020 ) to submit the permit applications and safe boarding plan. Further, BSEE mandated BDPL complete approved, permitted work within twelve (12) months (August 2020 ). BDPL timely submitted the permit applications and safe boarding plan to BOEM and BSEE onFebruary 11, 2020 ; we submitted related permits to the USACOE onMarch 25, 2020 . Although we planned decommissioning activities for 2020, offshore weather conditions and cash constraints associated with the ongoing COVID-19 pandemic led to delays. We cannot currently estimate when decommissioning will occur.
In
Financial constraints do not relieve BDPL of its obligations to remedy BSEE INCs or of BSEE's authority to impose financial penalties. If BDPL fails to complete decommissioning of the facilities assets or remedy the INCs within a timeframe deemed prudent by BSEE, BDPL could be subject to regulatory oversight and enforcement, including but not limited to failure to correct an INC, civil penalties, and revocation of BDPL's operator designation. Such BSEE actions could have a material adverse effect on our earnings, cash flows, and liquidity. We are currently unable to predict the outcome of the BSEE INCs. Accordingly, we have not recorded a liability on our consolidated balance sheet as ofSeptember 30, 2021 . At bothSeptember 30, 2021 , andDecember 31, 2020 , BDPL maintained$2.4 million in AROs related to decommissioning these assets. Sources and Use of Cash. Components of Cash Flows Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 2021 2020 (in thousands) (in thousands) Cash Flows Provided By (Used In): Operating activities$ 4,084 $ 1,658 $ (418 ) $ (2,196 ) Investing activities - (177 ) - (1,085 ) Financing activities 1,916 (1,243 )
696 3,451
Decrease in Cash and Cash Equivalents
Cash Flow We had cash flow from operations of approximately$4.1 million for Q3 2021 compared to approximately$1.7 million for Q3 2020. The improvement in cash flow from operations between the three-month comparative periods primarily related to an increase in unearned revenue. We had cash flow from operations of approximately$0.4 million for 9 Months 2021 compared to approximately$2.2 million for 9 Months 2020. The improvement in cash flow deficit between the nine-month periods primarily related to loss from operations.
Capital Expenditures
During Q3 2021, capital expenditures totaled$0 compared to$0.2 million during Q3 2020. During 9 Months 2021, capital expenditures totaled$0 compared to$1.1 million during 9 Months 2020. Capital expenditures during 2020 primarily related to completion of a petroleum storage tank and a maintenance turnaround. We completed the 5-yearNixon capital improvement expansion project during 9 Months 2020. Given the uncertainty surrounding the COVID-19 pandemic, combined with the volatile commodity price environment, we anticipate new capital expenditures to be minimal for the remainder of 2021 through the first half of 2022. We account for our capital expenditures per GAAP. We also classify capital expenditures as 'maintenance' if the expenditure maintains capacity or throughput or as 'expansion' if the expenditure increases capacity or throughput capabilities. Although classification is generally a straightforward process, the determination is a matter of management judgment and discretion in certain circumstances.
Table of Contents
Management's Discussion and Analysis
We identify and prioritize capital projects based on merits such as operational safety and efficiency, customer need, regulatory compliance, and economic benefits. We budget for maintenance capital expenditures throughout the year on a project-by-project basis.
Off-Balance Sheet Arrangements. None.
Accounting Standards.
Critical Accounting Policies and Estimates
We describe our significant accounting policies and recent accounting developments in "Part I, Item 1. Financial Statements - Note (2)". The ongoing COVID-19 pandemic and related governmental responses, volatility in commodity prices, and severe weather resulting from climate change have impacted and likely will continue to impact our business. Although management cannot predict the impact these factors will have on our future financial position and results of operations, historical facts serve as the basis for forecast assumptions. Management believes these assumptions are reasonable. We assessed certain accounting matters that generally require consideration of forecasted financial information in context with the information reasonably available to us and the unknown future impacts of COVID-19 as ofSeptember 30, 2021 , and through the filing date of this report. The accounting matters assessed included, but were not limited to, our allowance for doubtful accounts, inventory and related reserves, and the carrying value of long-lived assets.
New Accounting Standards and Disclosures
See "Part I, Item 1. Financial Statements - Note (2)" for a discussion of new accounting standards and disclosures.
Remainder of Page Intentionally Left Blank
Table of Contents Internal Controls
© Edgar Online, source
