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
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 fromWestern Canada to key demand centers acrossNorth 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 acrossNorth America . USDG's solutions create flexible market access for customers in significant growth areas and key demand centers, includingWestern Canada , theU.S. Gulf Coast andMexico . 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 inJanuary 2019 at the Partnership'sHardisty 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 inWestern Canada through the construction of a Diluent Recovery Unit, or DRU, at theHardisty Terminal and USD's new destination terminal inPort Arthur, Texas , or PAT. Construction of the DRU and PAT 35
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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 theAlberta 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 inCanada andthe United States . DRUbit™ is a market access solution that will help satisfy demand for heavy Canadian crude oil on theU.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 toU.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 ourHardisty 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 inMarch 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 36
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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 endedDecember 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, inJanuary 2021 , theCanadian 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 theU.S. andCanada 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 fromWestern Canada to theU.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 inCanada and higher apportionment and crude oil inventory levels, we expect that throughput volumes at ourHardisty 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 fromCanada to theU.S. is the significant regulatory and legal obstacles that pipeline projects and existing pipelines experience in theU.S. For example, inMarch 2020 , the government ofAlberta 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, inJanuary 2021 , the newU.S. President issued an executive action that revoked the permit for the Keystone XL pipeline and inJune 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 asMichigan's 37
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Governor previously demanded that the pipeline be shut down byMay 12, 2021 and revoked a 1953 Michigan easement that allowed Line 5 to pass through the bottom of the Straits ofMackinac . Line 5 has continued to operate despite theMichigan 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 andCanada 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. OurHardisty 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 endedDecember 31, 2020 , USD is pursuing long-term solutions to transport heavier grades of crude oil produced inWestern Canada through the construction of the DRU at theHardisty Terminal . Additionally, we believe ourStroud Terminal provides an advantageous rail destination for Western Canadian crude oil given the optionality provided by its connectivity to theCushing hub and multiple refining centers acrossthe 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 DevelopmentsHardisty and Stroud Terminal Services Agreements As previously discussed, construction of USD's DRU project was completed inJuly 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 ourHardisty andStroud terminals were made effective as ofAugust 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 endedDecember 31, 2020 . EffectiveAugust 2021 , the maturity date of three terminalling services agreements that are with the existing DRU customer at ourHardisty 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 ofJune 2022 . Effective with these changes, approximately 32% of theHardisty Terminal's capacity has been extended through mid-2031. Additionally effectiveAugust 2021 , the existing DRU customer has elected to reduce its volume commitments at theStroud Terminal attributable to the Partnership by one-third of the current commitment throughJune 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 theStroud Terminal . Management believes that the lower utilization at theStroud 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 theCushing oil hub. To facilitate this, USDM is currently working on an expansion of the downstream connectivity at ourStroud Terminal that when completed will add a pipeline connection to a second storage tank at a third-party facility at theCushing, 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 theStroud 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. 38
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West Colton Renewable Diesel Project InJune 2021 , we entered into a new Terminalling Services Agreement withUSD 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 ourWest 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 ofDecember 1, 2021 , and we are currently in the process of modifying our existingWest 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 ourWest Colton Terminal with USDCF discussed above, we also entered into a Marketing Services Agreement with USDCF inJune 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 theWest 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 InJune 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, datedOctober 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 onOctober 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. OurHardisty Terminal is an origination terminal where we load into railcars various grades of Canadian crude oil received from Gibson'sHardisty storage terminal. OurHardisty 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. OurStroud Terminal is a crude oil destination terminal inStroud, Oklahoma , which we use to facilitate rail-to-pipeline shipments of crude oil from ourHardisty Terminal to the crude oil storage hub located inCushing, 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 inCushing Oklahoma . OurStroud Terminal was purchased inJune 2017 and commenced operations inOctober 2017 . 39
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OurCasper 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. OurCasper Terminal is supplied with multiple grades of Canadian crude oil through a direct connection with the Express Pipeline. Additionally, theCasper Terminal has a connection from thePlatte terminal, where it has access to other pipelines and can receive other grades of crude oil, including locally sourcedWyoming 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 theCasper Terminal to the nearbyPlatte terminal located at the termination point of the Express pipeline that was placed into service inDecember 2019 . OurWest 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 theSan Bernardino and Riverside County-Inland Empire region ofSouthern 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 ofSeptember 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 ofSeptember 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 subsidiaryUSD 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 . 40
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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. 41
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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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