The following discussion and analysis provides information we believe is
relevant to understand our consolidated financial condition and results of
operations. This discussion should be read in conjunction with our unaudited
consolidated financial statements and accompanying notes contained in this
report together with our 2020 annual report. The results of operations for the
three and six months ended June 30, 2021, are not necessarily indicative of the
results we expect for the full year.
Cautionary Information Regarding Forward-Looking Statements
Forward-looking statements are made in accordance with safe harbor provisions of
the Private Securities Litigation Reform Act of 1995. These statements are based
on current expectations that involve a number of risks and uncertainties and do
not relate strictly to historical or current facts, but rather to plans and
objectives for future operations. These statements may be identified by words
such as "anticipate," "believe," "continue," "estimate," "expect," "intend,"
"outlook," "plan," "predict," "may," "could," "should," "will" and similar
expressions, as well as statements regarding future operating or financial
performance or guidance, business strategy, environment, key trends and benefits
of actual or planned acquisitions.
Factors that could cause actual results to differ from those expressed or
implied in the forward-looking statements include those discussed in Part I,
Item 1A, "Risk Factors," of our 2020 annual report and in Part II, Item 1A,
"Risk Factors," in this report, or incorporated by reference. Specifically, we
may experience fluctuations in future operating results due to disruption caused
by health epidemics, such as the COVID-19 outbreak; changes in general economic,
market or business conditions; foreign imports of ethanol; fluctuations in
demand for ethanol and other fuels; risks of accidents or other unscheduled
shutdowns affecting our assets, including mechanical breakdown of equipment or
infrastructure; risks associated with changes to federal policy or regulation;
ability to comply with changing government usage mandates and regulations
affecting the ethanol industry; price, availability and acceptance of
alternative fuels and alternative fuel vehicles, and laws mandating such fuels
or vehicles; changes in operational costs at our facilities and for our
railcars; failure to realize the benefits projected for capital projects;
competition; inability to successfully implement growth strategies; the supply
of corn and other feedstocks; unusual or severe weather conditions and natural
disasters; ability and willingness of parties with whom we have material
relationships, including Green Plains Trade, to fulfill their obligations; labor
and material shortages; changes in the availability of unsecured credit and
changes affecting the credit markets in general; risks related to acquisition
and disposition activities; and other risk factors detailed in our reports filed
with the SEC.
We believe our expectations regarding future events are based on reasonable
assumptions. However, these assumptions may not be accurate or account for all
risks and uncertainties. Consequently, forward-looking statements are not
guaranteed. Actual results may vary materially from those expressed or implied
in our forward-looking statements. In addition, we are not obligated nor do we
intend to update our forward-looking statements as a result of new information
unless it is required by applicable securities laws. We caution investors not to
place undue reliance on forward-looking statements, which represent management's
views as of the date of this report or documents incorporated by reference.
Overview
Green Plains Partners provides fuel storage and transportation services by
owning, operating, developing and acquiring ethanol and fuel storage facilities,
terminals, transportation assets and other related assets and businesses. We are
Green Plains' primary downstream logistics provider and generate a substantial
portion of our revenues under fee-based commercial agreements with Green Plains
Trade for receiving, storing, transferring and transporting ethanol and other
fuels, which are supported by minimum volume or take-or-pay capacity
commitments.
Recent Developments
Amendment to Credit Agreement
On July 20, 2021 we entered into an Amended and Restated Credit Agreement
("Amended Credit Facility") to our existing credit facility with funds and
accounts managed by BlackRock ("BlackRock") and TMI Trust Company as
administrative agent.
Under the terms of the agreement, BlackRock purchased the outstanding balance of
the existing notes from Bank of America N.A., as previous administrative agent,
and certain other commercial lending institutions. The Amended Credit Facility
will mature on July 20, 2026 and the principal amount available is $60.0
million. Interest on the Amended Credit Facility is based on 3-month LIBOR plus
8.00%, with a 0% LIBOR floor. Interest is payable on the 15th day of each March,
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June, September and December during the term with the first interest payment
being September 15, 2021. The Amended Credit Facility does not require any
principal payments; however, we have the option to prepay $1.5 million per
quarter beginning twelve months following closing. Financial covenants include a
maximum consolidated leverage ratio of 2.50x and a minimum consolidated debt
service coverage ratio of 1.10x. The Amended Credit Facility continues to be
secured by substantially all of the assets of the partnership.
Concurrent with the closing of the Amended Credit Facility, the board of
directors announced its intention to return to its prior strategy of maintaining
a 1.10x coverage ratio on normalized trailing 12-month distributable cash flow.
As the Amended Credit Facility does not have a revolving line of credit, we
believe the distribution strategy provides adequate liquidity to cover the
partnership's working capital needs.
Ord Disposition
On March 22, 2021, our parent closed on the sale of its ethanol plant located in
Ord, Nebraska to GreenAmerica Biofuels Ord LLC. Correspondingly, the storage
assets located adjacent to the Ord plant were sold to our parent for $27.5
million, along with the transfer of associated railcar operating leases.
As part of this transaction, we amended the storage and throughput agreement
with Green Plains Trade to reduce the quarterly minimum volume commitment from
232.5 mmg of product per calendar quarter to 217.7 mmg. In addition, the storage
and throughput agreement with Green Plains Trade was extended one additional
year to June 30, 2029. This transaction was reviewed and approved by the
conflicts committee.
Results of Operations
During the second quarter of 2021, our parent maintained an average utilization
rate of approximately 79.9% of capacity. Ethanol throughput was 191.8 mmg, which
was lower than the contracted minimum volume commitment per quarter. As a
result, the partnership charged Green Plains Trade $1.4 million related to the
minimum volume commitment deficiency for the quarter, resulting in a credit to
be applied against excess volumes in future periods. As of June 30, 2021, prior
year credits of $4.3 million expired, leaving a cumulative balance of minimum
volume deficiency credits available to Green Plains Trade of $7.7 million. These
credits expire, if unused, as follows:
?$2.4 million, expiring on September 30, 2021;
?$1.1 million, expiring on December 31, 2021;
?$2.8 million, expiring on March 31, 2022; and
?$1.4 million, expiring on June 30, 2022.
The above credits have been previously recognized as revenue by the partnership,
and as such, future volumes throughput by Green Plains Trade in excess of the
quarterly minimum volume commitment, up to the amount of these credits, will not
be recognized in revenue in future periods prior to expiration.
Our parent's operating strategy is to reduce operating expenses, energy usage,
and water consumption while running at higher utilization rates in order to
achieve improved margins. However, in the current environment, our parent may
exercise operational discretion that results in reductions in production.
Additionally, our parent may experience lower run rates due to the construction
of various projects. It is possible that production could be below minimum
volume commitments in the future, depending on various factors that drive each
biorefineries variable contribution margin, including future driving and
gasoline demand for the industry. At the same time, our parent is also focused
on the deployment of high protein technology at each of its facilities, which
could lead to our parent having more consistent margins and operating throughput
rates over time.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA is defined as earnings before interest expense, income tax
expense, depreciation and amortization excluding the amortization of
right-of-use assets, plus adjustments for transaction costs related to
acquisitions or financing transactions, unit-based compensation expense, net
gains or losses on asset sales, and our proportional share of EBITDA adjustments
of our equity method investee.
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Distributable cash flow is defined as adjusted EBITDA less interest paid or
payable, income taxes paid or payable, maintenance capital expenditures, which
are defined under our partnership agreement as cash expenditures (including
expenditures for the construction or development of new capital assets or the
replacement, improvement or expansion of existing capital assets) made to
maintain our operating capacity or operating income, and our proportional share
of distributable cash flow adjustments of our equity method investee.
Adjusted EBITDA and distributable cash flow are supplemental financial measures
that we use to assess our financial performance. We believe their presentation
provides useful information to investors in assessing our financial condition
and results of operations. However, these presentations are not made in
accordance with GAAP. The GAAP measure most directly comparable to adjusted
EBITDA and distributable cash flow is net income. Since adjusted EBITDA and
distributable cash flow may be defined differently by other companies in our
industry, our definitions of adjusted EBITDA and distributable cash flow may not
be comparable to similarly titled measures of other companies, diminishing their
utility. Adjusted EBITDA and distributable cash flow should not be considered in
isolation or as alternatives to net income or any other measure of financial
performance presented in accordance with GAAP to analyze our financial
performance and operating results.
The following table presents reconciliations of net income to adjusted EBITDA
and to distributable cash flow, for the three and six months ended June 30, 2021
and 2020 (unaudited, dollars in thousands):
Three Months Ended Six Months Ended
?June 30, ?June 30,
2021 2020 2021 2020
Reconciliations to Non-GAAP Financial
Measures:
Net income $ 10,298 $ 10,184 $ 21,025 $ 20,553
Interest expense 1,411 1,820 3,339 3,684
Income tax expense 68 105 152 136
Depreciation and amortization 795 966 1,682 1,927
Transaction costs - - 5 -
Unit-based compensation expense 80 79 159 158
Proportional share of EBITDA adjustments of
equity method investee (1) 50 44 94 94
Adjusted EBITDA 12,702 13,198 26,456 26,552
Interest paid or payable (1,411) (1,820) (3,339) (3,684)
Income taxes paid or payable (68) (30) (152) (61)
Maintenance capital expenditures - (32) (2) (54)
Distributable cash flow (2) $ 11,223 $ 11,316 $ 22,963 $ 22,753
Distributions declared (3) $ 2,844 $ 2,836 $ 5,686 $ 5,672
Coverage ratio 3.95x 3.99x 4.04x 4.01x
(1) Represents our proportional share of depreciation and amortization of our
equity method investee.
(2) Distributable cash flow does not include adjustments for the principal
payments on the term loan of $9.3 million, of which $0.5 million relates to the
Ord disposition, for the three months ended June 30, 2021, and $46.8 million, of
which $27.5 million relates to the Ord disposition, for the six months ended
June 30, 2021.
(3) Distributions declared for the applicable period and paid in the subsequent
quarter.
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Selected Financial Information and Operating Data
The following discussion reflects the results of the partnership for the three
and six months ended June 30, 2021 and 2020.
Selected financial information for the three and six months ended June 30, 2021
and 2020, is as follows (unaudited, in thousands):
Three Months Ended Six Months Ended
?June 30, ?June 30,
2021 2020 % Var. 2021 2020 % Var.
Revenues
Storage and throughput % %
services $ 11,564 $ 11,785 (1.9) $ 23,825 $ 23,570 1.1
Railcar transportation
services 4,795 5,374 (10.8) 9,837 10,498 (6.3)
Terminal services 2,218 2,132 4.0 4,260 4,326 (1.5)
Trucking and other 1,124 1,090 3.1 2,185 2,258 (3.2)
Total revenues 19,701 20,381 (3.3) 40,107 40,652 (1.3)
Operating expenses
Operations and
maintenance (excluding
depreciation and
amortization reflected
below) 6,238 6,603 (5.5) 11,992 12,763 (6.0)
General and
administrative 1,059 878 20.6 2,260 1,922 17.6
Depreciation and
amortization 795 966 (17.7) 1,682 1,927 (12.7)
Total operating expenses 8,092 8,447 (4.2) 15,934 16,612 (4.1)
Operating income $ 11,609 $ 11,934 (2.7) % $ 24,173 $ 24,040 0.6 %
Selected operating data for the three and six months ended June 30, 2021 and
2020, is as follows (unaudited):
Three Months Ended Six Months Ended
?June 30, ?June 30,
2021 2020 % Var. 2021 2020 % Var.
Product volumes (mmg)
Storage and throughput services 191.8 150.1 27.8 % 370.8 391.7 (5.3) %
Terminal services:
Affiliate 21.6 22.3 (3.1) 40.0 54.8 (27.0)
Non-affiliate 27.1 24.1 12.4 51.5 50.6 1.8
48.7 46.4 5.0 91.5 105.4 (13.2)
Railcar capacity billed (daily avg.) 69.4 80.9 (14.2) 71.2 79.8 (10.8)
Three Months Ended June 30, 2021, Compared with the Three Months Ended June 30,
2020
Consolidated revenues decreased $0.7 million for the three months ended June 30,
2021, compared with the same period for 2020. Railcar transportation services
revenue decreased $0.6 million primarily due to a reduction in average
volumetric capacity provided, and storage and throughput services revenue
decreased $0.2 million due to a decrease in throughput volumes, both of which
were a result of the sale of our parent's Hereford ethanol plant in the fourth
quarter of 2020 and its Ord ethanol plant in the first quarter of 2021. These
decreases were partially offset by an increase of $0.1 million in terminal
services revenue associated with minimum volume charges at our Birmingham
terminal.
Operations and maintenance expenses decreased $0.4 million for the three months
ended June 30, 2021, compared with the same period for 2020, primarily due to a
reduction in railcar lease expense as a result of our parent's sale of assets.
General and administrative expenses increased $0.2 million for the three months
ended June 30, 2021, compared with the same period for 2020, primarily due to an
increase in insurance expense.
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Six Months Ended June 30, 2021, Compared with the Six Months Ended June 30, 2020
Consolidated revenues decreased $0.5 million for the six months ended June 30,
2021, compared with the same period for 2020. Railcar transportation services
revenue decreased $0.7 million due to a reduction in average volumetric capacity
provided, as well as lower sublease revenue. Trucking and other revenue
decreased $0.1 million as a result of lower affiliate freight volume. Storage
and throughput services revenue increased $0.3 million due to an increase in the
rate per gallon charged to Green Plains Trade beginning on July 1, 2020,
partially offset by a decrease in throughput volumes as a result of our parent's
sale of the Hereford ethanol plant in the fourth quarter of 2020 and the Ord
ethanol plant in the first quarter of 2021.
Operations and maintenance expenses decreased $0.8 million for the six months
ended June 30, 2021, compared with the same period for 2020, primarily due to a
reduction in railcar lease expense, unloading fees, and repair and maintenance
as a result of our parent's sale of assets.
General and administrative expenses increased $0.3 million for the six months
ended June 30, 2021, compared with the same period for 2020, primarily due to an
increase in insurance expense.
Distributable cash flow increased $0.2 million for the six months ended June 30,
2021, compared with the same period for 2020, primarily due to an increase in
income from operations.
Industry Factors Affecting our Results of Operations
U.S. Ethanol Supply and Demand
According to the EIA, domestic ethanol production averaged 1.0 million barrels
per day during the second quarter of 2021, which was 42% higher than the 0.71
million barrels per day for the same quarter last year. Refiner and blender
input volume increased 35% to 903 thousand barrels per day for the second
quarter of 2021, compared with 669 thousand barrels per day for the same quarter
last year. Gasoline demand increased 2.1 million barrels per day, or 31% during
the second quarter of 2021 compared to the prior year. U.S. domestic ethanol
ending stocks increased by approximately 1.4 million barrels compared to the
prior year, or 7%, to 21.6 million barrels during the second quarter of 2021. As
of June 30, 2021, according to Prime the Pump, there were approximately 2,460
retail stations selling E15 in 30 states, up from 2,300 at the beginning of the
year, and approximately 245 pipeline terminal locations now offering E15 to
wholesale customers.
Global Ethanol Supply and Demand
According to the USDA Foreign Agriculture Service, domestic ethanol exports
through May 31, 2021 were approximately 582 mmg, down 10.7% from 652 mmg for the
same period of 2020. Canada was the largest export destination for U.S. ethanol
accounting for 22% of domestic ethanol export volume. India, China, South Korea,
and Brazil accounted for 18%, 17%, 12% and 5%, respectively, of U.S. ethanol
exports. We currently estimate that net ethanol exports will range from 1.2 to
1.4 billion gallons in 2021, based on historical demand from a variety of
countries and certain countries who seek to improve their air quality and
eliminate MTBE from their own fuel supplies.
In January 2020, China and the United States struck a "Phase I" trade agreement,
which included commitments on agricultural commodity purchases. Ethanol, corn
and distillers grains were included as potential purchases in the agreement.
China has been purchasing large quantities of corn, which has raised domestic
prices of this feedstock for our ethanol production process. In addition, in
October 2020 it was announced that China had purchased a shipment of U.S.
ethanol for the first time since March 2018. Total ethanol exports to China in
2020 were 21.3 million gallons, and through May 2021 were 100.1 million gallons,
according to the USDA Foreign Agriculture Service.
Legislation and Regulation
We are sensitive to government programs and policies that affect the supply and
demand for ethanol and other fuels, which in turn may impact the volume of
ethanol and other fuels we handle. Over the past few years, various bills and
amendments have been proposed in the House and Senate, which would eliminate the
RFS II entirely, eliminate the corn based ethanol portion of the mandate, and
make it more difficult to sell fuel blends with higher levels of ethanol. We
believe it is unlikely that any of these bills will become law in the current
Congress. In addition, the manner in which the EPA administers the RFS II and
related regulations can have a significant impact on the actual amount of
ethanol blended into the domestic fuel supply.
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Federal mandates and state-level clean fuel programs supporting the use of
renewable fuels are a significant driver of ethanol demand in the U.S. Ethanol
policies are influenced by concerns for the environment, diversifying our fuel
supply, and reducing the country's dependence on foreign oil. Consumer
acceptance of flex-fuel vehicles and higher ethanol blends of ethanol in
non-flex-fuel vehicles may be necessary before ethanol can achieve further
growth in U.S. market share. In addition, expansion of clean fuel programs in
other states, or a national low carbon fuel standard could increase the demand
for ethanol, depending on how it is structured.
Congress first enacted CAFE standards in 1975 to reduce energy consumption by
increasing the fuel economy of cars and light trucks. Flexible-fuel vehicles
(FFVs), which are designed to run on a mixture of fuels, including higher blends
of ethanol such as E85, used to receive preferential treatment in the form of
CAFE credits. There are approximately 21 million FFVs on the road in the U.S.
today, 16 million of which are light duty trucks. FFV credits have been
decreasing since 2014 and were completely phased out in 2020. Absent CAFE
preferences, auto manufacturers may not be willing to build flexible-fuel
vehicles, which has the potential to slow the growth of E85 markets. However,
California's Low Carbon Fuel Standard program (LCFS) has driven growth in E85
usage, and other state/regional LCFS programs have the potential to do the same.
The RFS II sets a floor for biofuels use in the United States. When the RFS II
was established in 2010, the required volume of "conventional" or corn-based
ethanol to be blended with gasoline was to increase each year until it reached
15.0 billion gallons in 2015, which left the EPA to address existing limitations
in both supply and demand. The EPA has not yet released a draft RVO rule for the
2021 or 2022 volumes, even though they typically release a draft mid-year and
finalize the rule by November 30 of the preceding year. As of this filing, the
EPA has not released the RVO for 2021 and 2022, although they are expected to
propose a joint rule in August or September of 2021 and finalize by the end of
the calendar year.
According to the RFS II, if mandatory renewable fuel volumes are reduced by at
least 20% for two consecutive years, the EPA is required to modify, or reset,
statutory volumes through 2022 - the year through which the statutorily
prescribed volumes run. While conventional ethanol maintained 15 billion
gallons, 2019 was the second consecutive year that the total RVO was more than
20% below the statutory volumes levels. Thus, the EPA was expected to initiate a
reset rulemaking, and modify statutory volumes through 2022, and do so based on
the same factors they are to use in setting the RVOs post-2022. These factors
include environmental impact, domestic energy security, expected production,
infrastructure impact, consumer costs, job creation, price of agricultural
commodities, food prices, and rural economic development. However, in late 2019,
the EPA announced it would not be moving forward with a reset rulemaking in
2020. It is unclear when or if the current EPA will propose a reset rulemaking,
though they have stated an intention to propose a post-2022 set rulemaking by
the end of 2021.
Under the RFS, RINs and SREs are important tools impacting supply and demand.
The EPA assigns individual refiners, blenders, and importers the volume of
renewable fuels they are obligated to use in each annual RVO based on their
percentage of total domestic transportation fuel sales. Obligated parties use
RINs to show compliance with the RFS II mandated volumes. Ethanol producers
assign RINs to renewable fuels and the RINs are detached when the renewable fuel
is blended with transportation fuel domestically. Market participants can trade
the detached RINs in the open market. The market price of detached RINs affects
the price of ethanol in certain markets and can influence purchasing decisions
by obligated parties. As it relates to SREs, a small refinery is defined as one
that processes fewer than 75,000 barrels of petroleum per day. Small refineries
can petition the EPA for a SRE which, if approved, waives their portion of the
annual RVO requirements. The EPA, through consultation with the DOE and the
USDA, can grant them a full or partial waiver, or deny it outright within 90
days of submittal. The EPA granted significantly more of these waivers for 2016,
2017 and 2018 than they had in the past, totaling 790 mmg of waived requirements
for the 2016 compliance year, 1.82 billion gallons for 2017 and 1.43 billion
gallons for 2018. In doing so, the EPA effectively reduced the RFS II mandated
volumes for those compliance years by those amounts respectively, and as a
result, RIN values declined significantly. In the waning days of the Trump
administration, the EPA approved three additional SREs, reversing one denial
from 2018 and granting two from 2019. A total of 88 SREs were granted under the
Trump Administration, totaling 4.3 billion gallons of potential blending demand
erased. The EPA, under the current administration, reversed the three SREs
issued in the final weeks of the previous administration.
The One-Pound Waiver that was extended in May 2019 to allow E15 to be sold
year-round to all vehicles model year 2001 and newer was challenged in an action
filed in Federal District Court for the D.C. Circuit. On July 2, 2021, the
Circuit Court vacated the EPA's rule so the future of summertime sales of E15 to
non-FFVs is uncertain. However, as of this filing, the One-Pound Waiver remains
in effect, and E15 is sold year-round in approximately 30 states. In January
2021, the EPA announced it intended to begin a rulemaking regarding E15 labels
and underground storage tank compatibility.
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Biofuels groups have filed a lawsuit in the Court of Appeals for the D.C.
Circuit, challenging the 2019 RVO rule over the EPA's failure to address small
refinery exemptions in the rulemaking. This was the first RFS II rulemaking
since the expanded use of the exemptions came to light; however, the EPA had
declined to cap the number of waivers it grants, and until late 2019, had
declined to alter how it accounts for the retroactive waivers in its annual
volume calculations. The EPA has a statutory mandate to ensure the volume
requirements are met, which is achieved by setting the percentage standards for
obligated parties. The EPA's recent approach accomplished the opposite. Even if
all the obligated parties complied with their respective percentage obligations
for 2019, the nation's overall supply of renewable fuel would not meet the total
volume requirements set by the EPA. This undermines Congressional intent to
increase the consumption of renewable fuels in the domestic transportation fuel
supply. Biofuels groups have argued the EPA must therefore adjust its percentage
standard calculations to make up for past retroactive waivers and adjust the
standards to account for any waivers it reasonably expects to grant in the
future.
In 2017, while citing inadequate domestic supply, the D.C. Circuit ruled in
favor of biofuel groups against the EPA related to its decision to lower the
2016 volume requirements by 500 mmg. As a result, the Court remanded to the EPA
to make up for the 500 mmg. Despite this, in the proposed 2020 RVO rulemaking
released in July 2019, the EPA stated it does not intend to make up the 500 mmg
as the court directed, citing potential burden on obligated parties. The EPA
had, at one point, indicated that it planned to address this court ordered
remand in conjunction with the 2021 RVO rulemaking; however that rulemaking has
been delayed indefinitely, and whether these gallons will be accounted for is
unclear.
In 2019, in a supplemental rulemaking to the 2020 RVO rule, the EPA changed
their approach, and for the first time accounted for the gallons that they
anticipate will be waived from the blending requirements due to small refinery
exemptions. To accomplish this, they added in the trailing three year average of
gallons the DOE recommended be waived, in effect raising the blending volumes
across the board in anticipation of waiving the obligations in whole or in part
for certain refineries that qualify for the exemptions. Though the EPA has often
disregarded the recommendations of the DOE in years past, they stated in the
rule their intent to adhere to these recommendations going forward, including
granting partial waivers rather than an all or nothing approach.
In January 2020, the U.S. Court of Appeals for the 10th Circuit ruled on RFA et.
al. vs. EPA in favor of biofuels interests, overturning EPA's granting of
refinery exemptions to three refineries on two separate grounds. The Court
agreed that, under the Clean Air Act, refineries are eligible for SREs for a
given RVO year only if such exemptions are extensions of exemptions granted in
previous RVO years. In this case, the three refineries at issue did not qualify
for SREs in the year prior to the year that EPA granted them. They were thus
ineligible for additional SRE relief because there were no immediately prior
SREs to extend. In addition, the Court agreed that the disproportionate economic
hardship prong of SRE eligibility should be determined solely by reference to
whether compliance with the RFS II creates such hardship, not whether compliance
plus other issues create disproportionate economic hardship. The Court thus
vacated EPA's grant of SREs for certain years and remanded the grants back
to EPA. The refiners appealed for a rehearing which was denied. Two of the
refiners appealed the decision to the U.S. Supreme Court and in January 2021,
the Supreme Court announced they would hear the case, and oral arguments were
held in late April 2021. In February 2021, the EPA indicated that it intends to
adhere to the 10th Circuit ruling. On June 25, 2021, the Supreme Court ruled
that the 10th Circuit's interpretation of "extension" was too narrow, and
vacated that portion of the ruling. As of this filing, it is unclear how this
Supreme Court decision may impact the EPA's handling of SREs.
In light of the 10th Circuit ruling, a number of refineries applied for "gap
year" SREs in an effort to establish a continuous string of relief and to ensure
they are able to qualify for SREs going forward. A total of 64 gap year requests
were filed with the EPA and reviewed by the DOE. In September 2020, the EPA
announced that they were denying 54 of the gap year requests that had been
scored and returned by DOE, regardless of how they had been scored.
In October 2019, the White House directed the USDA and EPA to move forward with
rulemaking to expand access to higher blends of biofuels. This includes funding
for infrastructure, labeling changes and allowing E15 to be sold through E10
infrastructure. The USDA rolled out the Higher Blend Infrastructure Incentive
Program in the summer of 2020, providing competitive grants to fuel terminals
and retailers for installing equipment for dispensing higher blends of ethanol
and biodiesel. In 2020, five Governors and 15 Republican Senators sent letters
to the EPA requesting a general waiver from the RFS due to the drop in demand
caused by COVID-19 travel restrictions. Since then there have been additional
petitions for waivers from the RFS requirements. As of this filing the EPA had
indicated only that they are watching the situation closely and reviewing the
various requests.
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To respond to the COVID-19 health crisis and attempt to offset the subsequent
economic damage, Congress passed multiple relief measures, most notably the
CARES Act in March 2020, which created and funded multiple programs that have
impacted our industry. The USDA was given additional resources for the Commodity
Credit Corporation (CCC) and they are using those funds to provide direct
payments to farmers, including corn farmers from whom our parent purchases most
of its feedstock for ethanol production. Similar to the trade aid payments made
by the USDA over the past two years, this cash injection for farmers could cause
them to delay marketing decisions and increase the price our parent has to pay
to purchase corn. The CARES Act also allowed for certain net operating loss
carrybacks, which has allowed us to receive certain tax refunds. In December
2020, Congress passed and the President signed into law an annual spending
package coupled with another COVID relief bill which included additional funds
for the Secretary of Agriculture to distribute to those impacted by the
pandemic. The language of the bill specifically includes biofuels producers as
eligible for some of this aid, and in March of 2021, the USDA indicated that
biofuels would be able to apply for a portion of these funds in a forthcoming
rulemaking. On June 15, 2021, the USDA indicated that $700 million would be made
available to biofuels producers, and that details for the program would be
released within 60 days.
The CARES Act provided a tax exclusion on the shipment of undenatured ethanol
for use in manufacturing hand sanitizer, a key ingredient of which is
undenatured ethanol of specific grades. The FDA has also provided expanded
guidance to allow for more denaturants to be used in ethanol intended for hand
sanitizer production, and has expanded the grades of ethanol allowed for the
duration of the public health crisis.
The current administration has indicated a desire to dramatically expand
electric vehicle (EV) charging stations, and initially proposed $174 billion for
EV charging infrastructure, purchase rebates, and other incentives. The
bipartisan infrastructure package being considered by Congress includes $15
billion for EV charging infrastructure, and $5 billion for electric busses and
ferries. Additionally, Congress is considering expanded EV incentives in a
potential partisan budget reconciliation package, with the goal of installing
500,000 EV charging stations and providing incentives to middle and lower income
Americans to purchase EVs.
Government actions abroad can significantly impact the demand for U.S. ethanol.
In September 2017, China's National Development and Reform Commission, the
National Energy Agency and 15 other state departments issued a joint plan to
expand the use and production of biofuels containing up to 10% ethanol by 2020.
China, the number three importer of U.S. ethanol in 2016, imported negligible
volumes during 2018 and 2019 due to a 30% tariff on U.S. ethanol, which
increased to 70% in early 2018. There is no assurance that China's joint plan to
expand blending to 10% will be carried to fruition, nor that it will lead to
increased imports of U.S. ethanol in the near term. Ethanol is included as an
agricultural commodity under the "Phase I" agreement with China, wherein they
are to purchase upwards of $40 billion in agricultural commodities from the U.S.
in both 2020 and 2021.
In Brazil, the Secretary of Foreign Trade had issued a tariff rate quota which
expired in December of 2020. All U.S. ethanol gallons now face a 20% tariff into
Brazil. Exports to Brazil were 200 mmg in 2020. Our exports also face tariffs,
rate quotas, countervailing duties, and other hurdles in the European Union,
India, Peru, Colombia and elsewhere, which limits the ability to compete in some
markets. We believe some countries are using the COVID-19 crisis as
justification for raising duties on imports of U.S. ethanol, or blocking imports
entirely.
In June 2017, the Energy Regulatory Commission of Mexico (CRE) approved the use
of 10% ethanol blends, which was challenged by multiple lawsuits, of which
several were dismissed. The remaining four cases follow one of two tracks: 1) to
determine the constitutionality of the CRE regulation, or 2) to determine the
benefits, or lack thereof, of introducing E10 to Mexico. An injunction was
granted in October 2017, preventing the blending and selling of E10, but was
overturned by a higher court in June 2018 making it legal to blend and sell E10
by PEMEX throughout Mexico except for its three largest metropolitan areas. On
January 15, 2020, the Mexican Supreme Court ruled that the expedited process for
the CRE regulation was unconstitutional, and that after a 180 day period the
maximum ethanol blend allowed in the country would revert to 5.8%. There was an
effort to go through the full regulatory process to allow for 10% blends
countrywide, including in the three major metropolitan areas. The 180 day window
was extended multiple times due to COVID-19, but eventually lapsed in June 2021,
decreasing the maximum ethanol blend back to 5.8%.
In January 2020, the updated North American Free Trade Agreement, known as the
United States Mexico Canada Agreement or USMCA was signed. The USMCA went into
effect on July 1, 2020, and maintains the duty free access of U.S. agricultural
commodities, including ethanol, into Canada and Mexico. According to the
Department of Commerce, exports to Canada were 326 mmg and exports to Mexico
were 64 mmg in 2020.
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Impact of COVID-19 and Decline in Oil Demand
The COVID-19 pandemic and related economic repercussions have created
significant volatility, uncertainty, and turmoil in the energy industry. The
situation surrounding COVID-19 continues to evolve rapidly and the ultimate
duration and impact of the outbreak as well as the continued decline in oil
demand remains highly uncertain and subject to change.
We continue to closely monitor the impact of COVID-19 on all aspects of our
business, including how it will impact our employees, customers, vendors, and
business partners. For the six months ended June 30, 2021, there has been no
adverse effect due to COVID-19 on our ability to maintain operations, including
our financial reporting systems, our internal controls over financial reporting
or our disclosure controls and procedures. In addition, to date we have not
incurred any material COVID-19 related contingencies. Although we did not incur
significant disruptions, we are unable to predict the impact that COVID-19 will
have on our future financial position and operating results, or that of our
parent from which we obtain a significant portion of our revenues, due to
numerous uncertainties.
For further information regarding the impact of COVID-19 and the decline in oil
demand on the partnership, please see Part I, Item 1A, "Risk Factors," of our
2020 annual report.
Liquidity and Capital Resources
Our principal sources of liquidity include cash generated from operating
activities and borrowings under our amended credit facility. We consider
opportunities to repay or refinance our debt, depending on market conditions, as
part of our normal course of doing business. Our ability to meet our debt
service obligations and other capital requirements depends on our future
operating performance, which is subject to general economic, financial,
business, competitive, legislative, regulatory and other conditions, many of
which are beyond our control. We expect operating cash flows will be sufficient
to meet our short-term and long-term liquidity needs, and plan to utilize a
combination of operating cash, refinancing and other strategic actions to fund
future expansion capital expenditures.
At June 30, 2021, we had $1.3 million of cash and cash equivalents and $5.0
million available under the revolving portion of our credit facility.
Net cash provided by operating activities was $24.2 million for the six months
ended June 30, 2021, compared with $22.2 million for the six months ended June
30, 2020. The increase in cash flows from operating activities resulted
primarily from an increase in net income as well as changes in net working
capital. Net cash provided by investing activities was $27.2 million for the six
months ended June 30, 2021, compared with net cash used in investing activities
of $54 thousand for the six months ended June 30, 2020, primarily as a result of
the Ord disposition in the first quarter of 2021. Net cash used in financing
activities was $52.5 million for the six months ended June 30, 2021, compared
with $19.4 million for the six months ended June 30, 2020. The increase was due
to principal payments on our term loan, partially offset by a decrease in our
quarterly distribution paid.
We incurred capital expenditures of $0.3 million for the six months ended June
30, 2021, primarily due to upgrades at our Wood River storage facility. We
expect to incur approximately $0.1 million in the remainder of 2021 for
additional capital costs related to these upgrades.
We did not make any equity method investee contributions related to the NLR
joint venture for the six months ended June 30, 2021, and we do not anticipate
making significant equity contributions to NLR for the remainder of 2021.
Credit Facility
As of June 30, 2021, Green Plains Operating Company had a credit facility to
fund working capital, capital expenditures and other general partnership
purposes. The credit facility included a $130.0 million term loan and a $5.0
million revolving credit facility, maturing on December 31, 2021. Monthly
principal payments increased from $2.5 million to $3.2 million beginning May 15,
2021 through maturity. As of June 30, 2021, the term loan had a balance of $53.2
million and an interest rate of 5.50%, and there were no outstanding swing line
loans.
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In certain situations we were required to make prepayments on the outstanding
principal balance on the credit facility. If at any time subsequent to July 15,
2020, our cash balance exceeded $2.5 million for more than five consecutive
business days, prepayments of outstanding principal were required in an amount
equal to the excess cash. We were also required to prepay outstanding principal
on the credit facility with 100% of net cash proceeds from any asset disposition
or recovery event. Any prepayments on the term loan were applied to the
remaining principal balance in inverse order of maturity, including the final
payment.
Principal payments of $46.8 million were made on the term loan during the six
months ended June 30, 2021, including $16.3 million of scheduled repayments,
$27.5 million related to the sale of the storage assets located adjacent to the
Ord, Nebraska ethanol plant and a $3.0 million prepayment made with excess cash.
As of June 30, 2021, no additional prepayments on the term loan were required.
On July 20, 2021 we entered into an Amended and Restated Credit Agreement
("Amended Credit Facility") to our existing credit facility with funds and
accounts managed by BlackRock ("BlackRock") and TMI Trust Company as
administrative agent.
Under the terms of the agreement, BlackRock purchased the outstanding balance of
the existing notes from Bank of America N.A., as previous administrative agent,
and certain other commercial lending institutions. The Amended Credit Facility
will mature on July 20, 2026 and the principal amount available is $60.0
million. Interest on the Amended Credit Facility is based on 3-month LIBOR plus
8.00%, with a 0% LIBOR floor. Interest is payable on the 15th day of each March,
June, September and December during the term with the first interest payment
being September 15, 2021. The Amended Credit Facility does not require any
principal payments; however, we have the option to prepay $1.5 million per
quarter beginning twelve months following closing. Financial covenants of the
agreement will include a maximum consolidated leverage ratio of 2.5x and a
minimum consolidated debt service coverage ratio of 1.10x. The Amended Credit
Facility continues to be secured by substantially all of the assets of the
partnership.
Concurrent with the closing of the Amended Credit Facility, the board of
directors announced its intention to return to its prior strategy of maintaining
a 1.10x coverage ratio on normalized trailing 12-month distributable cash flows.
As the Amended Credit Facility does not have a revolving line of credit, we
believe the distribution strategy provides adequate liquidity to cover our
working capital needs.
We use LIBOR as a reference rate for our credit facility. The administrator of
LIBOR has announced it will cease the publication of the one week and two month
LIBOR settings immediately following the LIBOR publication on December 31, 2021,
and the remaining USD LIBOR settings immediately following the LIBOR publication
on June 30, 2023. It is unclear if LIBOR will cease to exist or if new methods
of calculating LIBOR will be established by the applicable phase out dates. We
may need to amend our credit facility to determine the interest rate to replace
LIBOR with the new standard that is established. The potential effect of any
such event on interest expense cannot yet be determined.
For more information related to our debt, see Note 3 - Debt to the consolidated
financial statements in this report.
Distributions to Unitholders
On February 12, 2021, the partnership distributed $2.8 million to unitholders of
record as of February 5, 2021, related to the quarterly cash distribution of
$0.12 per unit that was declared on January 21, 2021, for the quarter ended
December 31, 2020.
On May 14, 2021, the partnership distributed $2.8 million to unitholders of
record as of May 7, 2021, related to the quarterly cash distribution of $0.12
per unit that was declared on April 22, 2021, for the quarter ended March 31,
2021.
On July 22, 2021, the board of directors of the general partner declared a
quarterly cash distribution of $0.12 per unit, or approximately $2.8 million,
for the quarter ended June 30, 2021. The distribution is payable on August 13,
2021, to unitholders of record at the close of business on August 6, 2021.
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Contractual Obligations
Our contractual obligations as of June 30, 2021, were as follows (in thousands):
Payments Due By Period
Less Than More Than
Contractual Obligations Total ?1 Year 1-3 Years 3-5 Years ?5 Years
Long-term debt obligations (1) $ 53,166 $ 53,166 $ - $ - $ -
Interest and fees on debt
obligations (2) 1,342 1,342 - - -
Operating leases (3) 48,311 14,130 21,399 10,072 2,710
Service agreements (4) 490 490 - - -
Other (5) 4,956 1,194 1,561 1,118 1,083
Total contractual obligations $ 108,265 $ 70,322 $ 22,960 $ 11,190 $ 3,793
(1) Includes the current portion of long-term debt and excludes the effect of
any debt discounts.
(2) Interest amounts are calculated based on the terms of the loans using
current interest rates, assuming scheduled principal and interest amounts are
paid pursuant to the credit agreement. Includes administrative and/or commitment
fees on debt obligations.
(3) Operating lease costs are primarily for property and railcar leases and
exclude leases not yet commenced with undiscounted future lease payments of
approximately $2.9 million.
(4) Service agreements are primarily related to minimum commitments on railcar
unloading contracts at our fuel terminals.
(5) Includes asset retirement obligations to return property and equipment to
its original condition at the termination of lease agreements.
Critical Accounting Policies and Estimates
Key accounting policies, including those relating to revenue recognition,
leases, impairment of long-lived assets and goodwill are impacted significantly
by judgments, assumptions and estimates used to prepare our consolidated
financial statements. Information about our critical accounting policies and
estimates is included in our 2020 annual report.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
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