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, 2022. 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, 2022 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.

The financial information for the three months ended March 31, 2022 has been retrospectively recast to include the pre-acquisition results of the Hardisty South Terminal because the acquisition represented a business combination between entities under common control. Refer to Part I. Item 1. Financial Statements, Note 3. Acquisitions and Dispositions of this Quarterly Report for more information.

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 one of 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 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.

USD's Diluent Recovery Unit and Port Arthur Terminal Projects

During 2021, USD, along with its joint venture partner, Gibson, successfully completed construction on and placed into service a diluent recovery unit, or DRU, at the Hardisty Terminal, as a part of a long-term solution to transport heavier grades of crude oil produced in Western Canada by rail. USD also placed into service a new destination terminal in Port Arthur, Texas, or PAT. Refer to the Growth Opportunities for our Operations section in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 for further information.



                                       28

--------------------------------------------------------------------------------

Casper Terminal Divestiture

On March 31, 2023, we completed our divestiture of all of the equity interests in our Casper Terminal, which included the Casper Crude to Rail, LLC and CCR Pipeline, LLC entities, for approximately $33 million in cash, subject to customary adjustments. Refer to Part I. Item 1. Financial Statements, Note 3. Acquisition and Dispositions - Casper Terminal Divestiture for additional details regarding this disposition. The Casper Terminal was included in our Terminalling Services segment.

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.

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. According to the Canadian Energy Regulator, or CER, the Canadian production forecast for 2023 is projected to grow which indicates another year of growth for Canadian production. Additionally, in March 2023, the Canadian Association of Petroleum Producers, or CAPP, announced that they are forecasting oil and natural gas investment in upstream production will hit C$40 billion in 2023, surpassing pre-COVID investment levels. This includes a planned investment of C$11.5 billion in the oil sands.

In the fourth quarter of 2022, TC Energy had a pipeline outage on the entire Keystone pipeline system. The entire pipeline was offline for a significant amount of time, which led to inventory builds in Canada. Given this event, Canadian crude oil inventory levels increased in the fourth quarter of 2022 and were at the higher end of the five year average. In the first quarter of 2023, the Keystone pipeline system came back online, which led to a minor storage draw and then storage levels stabilized and have remained at the higher end of the five year average through the end of the quarter.

Additionally, the U.S. government released approximately 260 million barrels of crude oil from the U.S. Strategic Petroleum Reserve, or SPR, starting in October 2021 and ending in January 2023. The impact of these emergency releases weakened replacement costs in the U.S. Gulf Coast for all sour crude oil alternatives. As replacement costs have weakened, WCS Houston crude prices have done the same, which has driven WCS Hardisty prices at origin to weaken in response. There are no further emergency SPR releases announced in the near term. However, regular planned releases started earlier than anticipated in the week ended March 31, 2023. The U.S government has announced plans to replenish the reserves by implementing a three-part strategy to refill the reserve in the long term, which includes repurchases, returns from previous exchanges and working with congress to avoid unnecessary sales. In early April 2023, the Organization of the Petroleum Exporting Countries and other oil producing countries, or OPEC+, announced unanticipated oil output cuts of around 1.16 million barrels per day. This action is expected to increase oil prices in the U.S.

Given the supply and demand events discussed above, and based on the forecasted production increases in Canada we expect that inventory levels in 2023 will remain at the higher end of the five year average. At these levels and as inventories continue to build, expectations are that pipeline apportionment levels will grow in the later part of 2023, which will potentially lead to higher demand for a crude by rail egress solution toward the end of 2023. However, the demand for crude by rail egress will be low in the near term due to planned and unplanned maintenance on both oil sands production assets and refineries and increased pipeline egress availability due to drag



                                       29

--------------------------------------------------------------------------------

reducing agent usage and favorable pipeline summer blending ratio requirements. 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 demand for a crude by rail egress solution is the significant regulatory and legal obstacles that pipeline projects and existing pipelines experience in the U.S and Canada. For example, it was recently announced by Trans Mountain Corporation, or TMC, that the total cost of the Trans Mountain Pipeline expansion project is now estimated to be $30.9 billion. TMC is currently working to secure external financing to fund the remaining cost of the project. The timeline for completing the project is now extended out further into the end of 2023, with in-service announced to be in early 2024. As environmental, regulatory and political challenges to increase pipeline export capacity remain, we believe crude by rail exports will remain a valuable egress solution.

Our Hardisty terminal, with established capacity and scalable designs, is well-positioned as strategic outlets to meet takeaway needs when Western Canadian crude oil supplies continue to exceed available pipeline takeaway capacity. Also, as previously discussed, USD along with its partner, successfully completed construction of and placed into service a diluent recovery unit, or DRU, at the Hardisty Terminal, as a part of a long-term solution to transport heavier grades of crude oil produced in Western Canada by rail. 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. Although in the long-term we expect that these advantages could result in contract extensions and expansion opportunities across our terminal network, we have not been able to renew or replace contracts that expired in June 2022 and may not be able to renew or replace contracts that are expiring in June 2023 and January 2024. This will make it challenging for us to renew, extend or replace our amended Credit Agreement that expires in early November 2023.

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.

Our combined Hardisty Terminal is an origination terminal where various grades of Canadian crude oil received from Gibson's Hardisty storage terminal and DRUbitTM from our Sponsor's DRU facility are loaded into railcars. Our combined Hardisty Terminal can load up to three and one-half 120-railcar unit trains per day and consists of a fixed loading rack with approximately 60 railcar loading positions, and unit train staging with 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.

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



                                       30

--------------------------------------------------------------------------------

Bernardino and Riverside County-Inland Empire region of Southern California. The West Colton Terminal has 20 railcar offloading positions and four 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 take-or-pay terms under a master fleet services agreement. We do not own any railcars. As of March 31, 2023, 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 three months as of March 31, 2023. The Partnership is currently working on extending the fleet agreements for the 200 railcars beyond the current June 30, 2023 end date through December 2023, which we anticipate could be executed sometime in the second quarter of 2023.

Under the master fleet services agreement, we provide our customer 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 1. Financial Statements, Note 14. Segment Reporting of this Quarterly Report.

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.



                                       31

--------------------------------------------------------------------------------

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.

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

© Edgar Online, source Glimpses