The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with the unaudited consolidated financial statements and accompanying notes in "Item 1. Financial Statements" contained herein and our audited consolidated financial statements and accompanying notes included in "Item 8. Financial Statements and Supplementary Data" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020. Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following discussion and analysis. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in "Item 1A. Risk Factors" included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020 and subsequent Quarterly Reports on Form 10-Q. Please also read the "Cautionary Note Regarding Forward-Looking Statements" following the table of contents in this Report. We denote amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount.

Overview


We are a fee-based, growth-oriented master limited partnership formed by our
sponsor, USD, to acquire, develop and operate midstream infrastructure and
complementary logistics solutions for crude oil, biofuels and other
energy-related products. We generate substantially all of our operating cash
flows from multi-year, take-or-pay contracts with primarily investment grade
customers, including major integrated oil companies, refiners and marketers. Our
network of crude oil terminals facilitates the transportation of heavy crude oil
from Western Canada to key demand centers across North America. Our operations
include railcar loading and unloading, storage and blending in onsite tanks,
inbound and outbound pipeline connectivity, truck transloading, as well as other
related logistics services. We also provide our customers with leased railcars
and fleet services to facilitate the transportation of liquid hydrocarbons by
rail.
We generally do not take ownership of the products that we handle nor do we
receive any payments from our customers based on the value of such products. We
may on occasion enter into buy-sell arrangements in which we take temporary
title to commodities while in our terminals. We expect any such arrangements to
be at fixed prices where we do not take any exposure to changes in commodity
prices.
We believe rail will continue as an important transportation option for energy
producers, refiners and marketers due to its unique advantages relative to other
transportation means. Specifically, rail transportation of energy-related
products provides flexible access to key demand centers on a relatively low
fixed-cost basis with faster physical delivery, while preserving the specific
quality of customer products over long distances.
USDG, a wholly-owned subsidiary of USD, and the sole owner of our general
partner, is engaged in designing, developing, owning, and managing large-scale
multi-modal logistics centers and energy-related infrastructure across North
America. USDG's solutions create flexible market access for customers in
significant growth areas and key demand centers, including Western Canada, the
U.S. Gulf Coast and Mexico. Among other projects, USDG is currently pursuing the
development of a premier energy logistics terminal on the Houston Ship Channel
with capacity for substantial tank storage, multiple docks (including barge and
deepwater), inbound and outbound pipeline connectivity, as well as a rail
terminal with unit train capabilities. USDG completed an expansion project in
January 2019 at the Partnership's Hardisty Terminal, referred to herein as
Hardisty South, which added one and one-half 120-railcar unit trains of
transloading capacity per day, or approximately 112,500 barrels per day, or bpd.
USD's Diluent Recovery Unit and Port Arthur Terminal Projects
USD, along with its partner, Gibson, are progressing on a long-term solution to
transport heavier grades of crude oil produced in Western Canada through the
construction of a Diluent Recovery Unit, or DRU, at the Hardisty Terminal and
USD's new destination terminal in Port Arthur, Texas, or PAT. Construction of
the DRU and PAT

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projects is complete and both the DRU and PAT are now operating in the start-up
phase, and throughput volumes are consistent with contractual obligations and
our customer's expectations.
USD's patented DRU technology separates the diluent that has been added to the
raw bitumen in the production process which meets two important market needs -
it returns the recovered diluent for reuse in the Alberta market, reducing
delivered costs for diluent, and it creates DRUbit™, a proprietary heavy
Canadian crude oil specifically designed for rail transportation. DRUbit™ is
crude oil or bitumen that has been returned to a more concentrated, viscous
state that is classified as a non-hazardous, non-flammable commodity when
transported by rail in Canada and the United States. DRUbit™ is a market access
solution that will help satisfy demand for heavy Canadian crude oil on the U.S.
Gulf Coast and in other markets at a cost that is economically competitive to
the crude oil that is transported by pipeline. PAT is currently capable of
receiving DRUbit™ by rail and diluent and C5 blends stocks from the newly
constructed pipeline and by barge at the terminal. The terminal can facilitate
the blending of the products on site through newly constructed storage tanks and
deliver the blended product back through the pipeline or barged via the marine
facility to U.S Gulf Coast refineries.
The successful commencement of USD's DRU project enhances the sustainability and
quality of our cash flows by significantly increasing the tenor of three
terminalling services agreements at our Hardisty Terminal, representing
approximately 32% of the terminal's capacity, through mid-2031. Refer to the
discussion in Commercial Developments - Hardisty and Stroud Terminal Services
Agreements below for more detail.
Recent Developments
Market Update
Substantially all of our operating cash flows are generated from take-or-pay
contracts and, as a result, are not directly related to actual throughput
volumes at our crude oil terminals. Throughput volumes at our terminals are
primarily influenced by the difference in price between Western Canadian Select,
or WCS, and other grades of crude oil, commonly referred to as spreads, rather
than absolute price levels. WCS spreads are influenced by several market
factors, including the availability of supplies relative to the level of demand
from refiners and other end users, the price and availability of alternative
grades of crude oil, the availability of takeaway capacity, as well as
transportation costs from supply areas to demand centers.
COVID-19 and Crude Oil Pricing Environment Update
During 2020, the COVID-19 pandemic adversely affected the global economy,
disrupted global supply chains and created significant volatility in the
financial markets. As a result, beginning in March 2020, there was significant
reductions in demand for crude oil, natural gas and natural gas liquids, which
led to a decline in commodity prices. This drove Canadian producers to curtail
production, which in turn resulted in lower crude oil supply levels and led to
lower throughput volume through our facilities.
Vaccination implementation and efforts to reopen the economy to date in 2021
have driven demand for crude oil and petroleum products to near pre-COVID
levels. As a result, crude oil prices have recovered and stabilized at higher
than pre-pandemic levels and continued to strengthen through the third quarter
of 2021. In October of 2021, WTI prices topped $80 per barrel, which represents
the highest price levels for WTI since 2014. Given these higher prices and
currently tight discount levels in the Canadian heavy market, Canadian producers
are achieving higher netbacks than pre-pandemic levels. We believe that if the
increases in demand for oil and natural gas continue, global production levels
will generally be higher during the remainder of 2021, continuing into 2022.
However, there still remains significant uncertainty given the unprecedented and
evolving nature of the COVID-19 pandemic, and the extent of any increases in
demand and price levels are difficult to predict.
The broader implications of COVID-19 and volatile oil and natural gas prices on
our results of operations and overall financial performance remain uncertain. We
have implemented protocols and procedures designed to manage risk associated
with the direct impact of COVID-19 on our operations. We have not experienced
material disruptions to our operations or material increase in our cash
expenses. Currently, we expect to have sufficient liquidity to operate our
business and remain in compliance with the financial covenants under our credit
agreement for at least the next twelve months following the filing of this
report and we do not expect our customers to terminate existing

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contracts. However, if the pandemic continues for a further extended period of
time, COVID-19 related lockdowns or other restrictions are reinstated and/or oil
prices decrease to relatively low levels, these conditions may have an adverse
effect on the Company's results of future operations, financial position, and
liquidity. Given the unprecedented and evolving nature of the COVID-19 pandemic
and the state of the commodity markets, we continue to actively monitor their
impact on our operations and financial condition. Refer to Item 1A. Risk Factors
in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020
for further discussion of certain risks relating to the COVID-19 pandemic.
Impact of Current Market Events
Given that crude oil prices have recovered and are higher than pre-COVID levels,
Canadian production that was temporarily shut-in due to COVID-19 has also
returned to pre-COVID levels. Additionally, in January 2021, the Canadian
Association of Petroleum Producers, or CAPP, announced that they are forecasting
more than a $3 billion dollar increase in planned upstream oil and gas spending
as compared to 2020 levels. Recent quarterly earnings calls and announcements
indicate that Canadian producers are generating excess cash flow and have
expressed plans to reinvest the profits into production expansions and
optimizations, which, to the extent such plans are carried out, we anticipate
could drive supply to greater than pre-COVID levels through 2022.
Although supply has increased to date in 2021, relative to 2020, during the
third quarter of 2021, specific unanticipated supply and demand events have
delayed Canadian producers' return to crude by rail egress solutions. For
example, planned and unplanned outages or maintenance on production assets of
certain Canadian producers and COVID-19 impacts on planned ramp-up schedules
created an unexpected reduction to Canadian supply during the third quarter of
2021. Additionally, pipeline projects previously anticipated to be delayed by
the regulatory process went into service on schedule, creating additional
pipeline egress capacity. The in-service activities of these pipelines in the
U.S. and Canada create an incremental one-time demand for crude oil to satisfy
pipeline line fill requirements, causing an additional draw on Canadian crude
inventories. The specific supply reductions and one-time demand event increases
during the third quarter of 2021 and carryover impacts of these events into the
fourth quarter of 2021 have resulted in a temporary delay in the demand for
Canadian crude by rail egress solutions that is expected to carry into 2022.
Despite the macro events impacting Western Canadian supply and demand balances
described above, apportionment levels (representing the percentage of barrels
nominated that were not shipped due to pipeline capacity constraints) on the
primary heavy crude oil pipelines from Western Canada to the U.S. increased to
an average of 53%. Crude inventory levels decreased during the third quarter of
2021 as compared to levels that existed at the end of the second quarter in 2021
due to those supply and demand events previously discussed but still remain at
high levels on an annual relative basis. Consistent with the increases in supply
and apportionment levels that have occurred throughout 2021, crude oil inventory
levels increased by approximately 12% as of the end of the third quarter of
2021, as compared to levels at the end of the fourth quarter 2020.
Based on the forecasted crude oil production increases in Canada and higher
apportionment and crude oil inventory levels, we expect that throughput volumes
at our Hardisty Terminal will trend upwards from the low levels that existed
during 2020, with the potential of reaching pre-COVID levels in 2022. There
still remains significant uncertainty given the unprecedented and evolving
nature of the COVID-19 pandemic, and the extent and duration of any increases in
apportionment or inventory levels are difficult to predict, if such increases
occur at all.
Another factor that may contribute to the use of rail to export crude oil from
Canada to the U.S. is the significant regulatory and legal obstacles that
pipeline projects and existing pipelines experience in the U.S. For example, in
March 2020, the government of Alberta announced that it had reached an agreement
to make a $1.5 billion equity investment in the Keystone XL crude oil pipeline
project in 2020 followed by a $6 billion loan guarantee in 2021 in order to
enable the completion of the project by 2023. However, in January 2021, the new
U.S. President issued an executive action that revoked the permit for the
Keystone XL pipeline and in June 2021, the Keystone XL pipeline project was
officially cancelled by TC Energy. Current pipeline operators are also facing
legal challenges to keep their pipelines in operation. The Dakota Access
Pipeline is in the middle of a legal dispute to determine whether the pipeline
can continue to operate without a key easement, although the pipeline can
operate until a decision is made by federal courts. Enbridge's Line 5 is also in
jeopardy of being shut down as Michigan's

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Governor previously demanded that the pipeline be shut down by May 12, 2021 and
revoked a 1953 Michigan easement that allowed Line 5 to pass through the bottom
of the Straits of Mackinac. Line 5 has continued to operate despite the Michigan
Governor's demand. The Army Corps of Engineers has since added an additional
environmental impact study on a submerged tunnel included in the project which
is expected to delay the project's in service date to 2025. Most recently, to
escalate the Line 5 dispute to the US Federal government, the Canadian
government has invoked a Transit Pipelines Treaty that was established between
US and Canada in 1977. As environmental, regulatory and political challenges to
increase pipeline export capacity remain, crude by rail exports will remain a
valuable egress solution.
In the long-term, as stated above, we expect demand for rail capacity at our
terminals to continue to increase over the next several years and potentially
longer if proposed pipeline developments do not meet currently planned timelines
and regulatory or other challenges to pipeline projects persist. Our Hardisty
and Casper Terminals, with established capacity and scalable designs, are
well-positioned as strategic outlets to meet takeaway needs as Western Canadian
crude oil supplies continue to exceed available pipeline takeaway capacity.
Also, as discussed in more detail in our Annual Report on Form 10-K for the
fiscal year ended December 31, 2020, USD is pursuing long-term solutions to
transport heavier grades of crude oil produced in Western Canada through the
construction of the DRU at the Hardisty Terminal. Additionally, we believe our
Stroud Terminal provides an advantageous rail destination for Western Canadian
crude oil given the optionality provided by its connectivity to the Cushing hub
and multiple refining centers across the United States. Rail also generally
provides a greater ability to preserve the specific quality of a customer's
product relative to pipelines, providing value to a producer or refiner. We
expect these advantages, including our origin-to-destination capabilities, to
continue to result in long-term contract extensions and expansion opportunities
across our terminal network.
Commercial Developments
Hardisty and Stroud Terminal Services Agreements
As previously discussed, construction of USD's DRU project was completed in July
2021. The DRU is now operating in the start-up phase and throughput volumes are
consistent with contractual obligations and our customer's expectations. As
such, the following changes to the terminalling services agreements at our
Hardisty and Stroud terminals were made effective as of August 2021, as
discussed in detail in Item 1 Business - Business Segments - Terminalling
Services - Hardisty Terminal in our Annual Report on Form 10-K for the fiscal
year ended December 31, 2020.
Effective August 2021, the maturity date of three terminalling services
agreements that are with the existing DRU customer at our Hardisty Terminal have
been extended through mid-2031, with two-thirds of the volume commitment with
respect to one of these agreements terminating at the end of June 2022.
Effective with these changes, approximately 32% of the Hardisty Terminal's
capacity has been extended through mid-2031.
Additionally effective August 2021, the existing DRU customer has elected to
reduce its volume commitments at the Stroud Terminal attributable to the
Partnership by one-third of the current commitment through June 2022, at which
point the agreement will terminate and there will be no renewal period. The
existing DRU customer has also elected to fully terminate the volume commitments
attributable to USDM at the Stroud Terminal. Management believes that the lower
utilization at the Stroud Terminal as a result of successful commencement of the
DRU project will be short-term in nature and will allow the Partnership the
opportunity to offer terminalling services to other customers that may be in
need of access to the numerous markets connected to the Cushing oil hub.
To facilitate this, USDM is currently working on an expansion of the downstream
connectivity at our Stroud Terminal that when completed will add a pipeline
connection to a second storage tank at a third-party facility at the Cushing,
Oklahoma crude oil hub, or the Cushing Hub. The expanded connectivity is
expected to facilitate incremental rail-to-pipeline shipments of crude oil to
the Cushing Hub by giving the Stroud Terminal better capability to service
multiple customers and/or grades of crude oil simultaneously. The expansion is
expected to be completed in the first quarter of 2022.

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West Colton Renewable Diesel Project
In June 2021, we entered into a new Terminalling Services Agreement with USD
Clean Fuels LLC, or USDCF, a newly formed subsidiary of USD, that is supported
by a minimum throughput commitment to USDCF from an investment-grade rated,
refining customer as well as a performance guaranty from USD. The Terminal
Services Agreement provides for the inbound shipment of renewable diesel on rail
at our West Colton Terminal and the outbound shipment of the product on tank
trucks to local consumers. The new terminalling services agreement has an
initial term of five years with a target commencement date of December 1, 2021,
and we are currently in the process of modifying our existing West Colton
Terminal so that it will have the capability to transload renewable diesel in
addition to the ethanol that it is currently transloading. Refer to   Liquidity
and Capital Resources   - Cash Requirements - Capital Requirements for more
detail on the capital expenditures associated with this project.
In exchange for the new terminalling agreement at our West Colton Terminal with
USDCF discussed above, we also entered into a Marketing Services Agreement with
USDCF in June 2021, or the West Colton MSA, pursuant to which we agreed to grant
USDCF marketing and development rights pertaining to future renewable diesel
opportunities associated with the West Colton Terminal in excess of the
terminalling services agreement with USDCF discussed above. Refer to Part I.
Item 1. Financial Statements,   Note 12. Transactions with Related Parties   for
further information.
Right of First Offer
In June 2021, we entered into an Amended and Restated Omnibus Agreement, or the
Amended Omnibus Agreement, with USD, USDG and certain of their subsidiaries,
which amends and restates the Omnibus Agreement, dated October 15, 2014, to
extend the termination date of the right of first offer period, or ROFO Period,
as defined in the Amended Omnibus Agreement, by an additional five years such
that the ROFO Period will terminate on October 15, 2026 unless a Partnership
Change of Control, as defined in the Amended Omnibus Agreement, occurs prior to
such date.

How We Generate Revenue
We conduct our business through two distinct reporting segments: Terminalling
services and Fleet services. We have established these reporting segments as
strategic business units to facilitate the achievement of our long-term
objectives, to assist in resource allocation decisions and to assess operational
performance.
Terminalling Services
The terminalling services segment includes a network of strategically-located
terminals that provide customers with railcar loading and/or unloading capacity,
as well as related logistics services, for crude oil and biofuels. Substantially
all of our cash flows are generated under multi-year, take-or-pay terminal
services agreements that include minimum monthly commitment fees. We generally
have no direct commodity price exposure, although fluctuating commodity prices
could indirectly influence our activities and results of operations over the
long term. We may on occasion enter into buy-sell arrangements in which we take
temporary title to commodities while in our terminals. We expect any such
agreements to be at fixed prices where we do not take commodity price exposure.
Our Hardisty Terminal is an origination terminal where we load into railcars
various grades of Canadian crude oil received from Gibson's Hardisty storage
terminal. Our Hardisty Terminal can load up to two 120-railcar unit trains per
day and consists of a fixed loading rack with approximately 30 railcar loading
positions, a unit train staging area and loop tracks capable of holding five
unit trains simultaneously.
Our Stroud Terminal is a crude oil destination terminal in Stroud, Oklahoma,
which we use to facilitate rail-to-pipeline shipments of crude oil from our
Hardisty Terminal to the crude oil storage hub located in Cushing, Oklahoma. The
Stroud Terminal includes 76-acres with current unit train unloading capacity of
approximately 50,000 Bpd, two onsite tanks with 140,000 barrels of capacity, one
truck bay, and a 12-inch diameter, 17-mile pipeline with a direct connection to
the crude oil storage hub in Cushing Oklahoma. Our Stroud Terminal was purchased
in June 2017 and commenced operations in October 2017.

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Our Casper Terminal is a crude oil storage, blending and railcar loading
terminal. The terminal currently offers six storage tanks with 900,000 barrels
of total capacity, unit train-capable railcar loading capacity in excess of
100,000 bpd, as well as truck transloading capacity. Our Casper Terminal is
supplied with multiple grades of Canadian crude oil through a direct connection
with the Express Pipeline. Additionally, the Casper Terminal has a connection
from the Platte terminal, where it has access to other pipelines and can receive
other grades of crude oil, including locally sourced Wyoming sour crude oil. The
Casper Terminal can also receive volumes through one truck unloading station and
is also equipped with one truck loading station. Additionally, to supplement the
rail loading options from the terminal, we constructed an outbound pipeline
connection from the Casper Terminal to the nearby Platte terminal located at the
termination point of the Express pipeline that was placed into service in
December 2019.
Our West Colton Terminal is a unit train-capable destination terminal that can
transload up to 13,000 bpd of ethanol and renewable diesel received from
producers by rail onto trucks to meet local demand in the San Bernardino and
Riverside County-Inland Empire region of Southern California. The West Colton
Terminal has 20 railcar offloading positions and three truck loading positions.
Fleet Services
We provide one of our customers with leased railcars and fleet services related
to the transportation of liquid hydrocarbons by rail on multi-year, take-or-pay
terms under a master fleet services agreement. We do not own any railcars. As of
September 30, 2021, our railcar fleet consisted of 200 railcars, which we lease
from a railcar manufacturer, all of which are coiled and insulated, or C&I,
railcars. The weighted average remaining contract life on our railcar fleet is
1.25 years as of September 30, 2021.
Under the master fleet services agreement, we provide customers with
railcar-specific fleet services, which may include, among other things, the
provision of relevant administrative and billing services, the repair and
maintenance of railcars in accordance with standard industry practice and
applicable law, the management and tracking of the movement of railcars, the
regulatory and administrative reporting and compliance as required in connection
with the movement of railcars, and the negotiation for and sourcing of railcars.
Our customer typically pays us and our assignees monthly fees per railcar for
these services, which include a component for fleet services.
Historically, we contracted with railroads on behalf of some of our customers to
arrange for the movement of railcars from our terminals to the destinations
selected by our customers. We were the contracting party with the railroads for
those shipments and were responsible to the railroads for the related fees
charged by the railroads, for which we were reimbursed by our customers. Both
the fees charged by the railroads to us and the reimbursement of these fees by
our customers are included in our consolidated statements of operations in the
revenues and operating costs line items entitled "Freight and other
reimbursables."
Also, we have historically assisted our customers with procuring railcars to
facilitate their use of our terminalling services. Our wholly-owned subsidiary
USD Rail LP has historically entered into leases with third-party manufacturers
of railcars and financial firms, which it has then leased to customers. Although
we expect to continue to assist our customers in obtaining railcars for their
use transporting crude oil to or from our terminals, we do not intend to
continue to act as an intermediary between railcar lessors and our customers as
our existing lease agreements expire, are otherwise terminated, or are assigned
to our existing customers. Should market conditions change, we could potentially
act as an intermediary with railcar lessors on behalf of our customers again in
the future.
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics to evaluate our
operations. When we evaluate our consolidated operations and related liquidity,
we consider these metrics to be significant factors in assessing our ability to
generate cash and pay distributions and include: (i) Adjusted EBITDA and DCF;
(ii) operating costs; and (iii) volumes. We define Adjusted EBITDA and DCF
below. When evaluating our operations at the segment level, we evaluate using
Segment Adjusted EBITDA. Refer to   Part I, Item 8. Financial Statements and
Supplementary Data, Note 14. Segment Reporting  .


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Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as "Net cash provided by operating activities"
adjusted for changes in working capital items, interest, income taxes, foreign
currency transaction gains and losses, and other items which do not affect the
underlying cash flows produced by our businesses. Adjusted EBITDA is a non-GAAP,
supplemental financial measure used by management and external users of our
financial statements, such as investors and commercial banks, to assess:
•our liquidity and the ability of our business to produce sufficient cash flow
to make distributions to our unitholders; and
•our ability to incur and service debt and fund capital expenditures.
We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid
for interest, income taxes and maintenance capital expenditures. DCF does not
reflect changes in working capital balances. DCF is a non-GAAP, supplemental
financial measure used by management and by external users of our financial
statements, such as investors and commercial banks, to assess:
•the amount of cash available for making distributions to our unitholders;
•the excess cash flow being retained for use in enhancing our existing business;
and
•the sustainability of our current distribution rate per unit.
We believe that the presentation of Adjusted EBITDA and DCF in this Report
provides information that enhances an investor's understanding of our ability to
generate cash for payment of distributions and other purposes. The GAAP measure
most directly comparable to Adjusted EBITDA and DCF is "Net cash provided by
operating activities." Adjusted EBITDA and DCF should not be considered
alternatives to "Net cash provided by operating activities" or any other measure
of liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF exclude
some, but not all, items that affect "Net cash provided by operating
activities," and these measures may vary among other companies. As a result,
Adjusted EBITDA and DCF may not be comparable to similarly titled measures of
other companies.

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The following table sets forth a reconciliation of Net cash provided by operating activities, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted EBITDA and DCF:

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