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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to       
Commission file number 001-36674
USD PARTNERS LP
(Exact name of registrant as specified in its charter)
Delaware 30-0831007
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
811 Main Street, Suite 2800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (281) 291-0510
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol Name of each exchange on which registered
Common Units Representing Limited Partner Interests USDP New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨   
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  No x
As of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s common units held by non-affiliates was $45,245,426 computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity.
As of February 24, 2021, the registrant has outstanding 27,224,441 common units and 461,136 general partner units.

DOCUMENTS INCORPORATED BY REFERENCE: NONE



TABLE OF CONTENTS
Page
1
Unless the context otherwise requires, all references in this Annual Report on Form 10-K, or this “Annual Report” or this “Form 10-K” to “USD Partners,” “USDP,” “the Partnership,” “we,” “us,” “our,” or like terms refer to USD Partners LP and its subsidiaries.
Unless the context otherwise requires, all references in this Annual Report to (i) “our general partner” refer to USD Partners GP LLC, a Delaware limited liability company; (ii) “USD” refers to US Development Group, LLC, a Delaware limited liability company, and where the context requires, its subsidiaries; (iii) “USDG” and “our sponsor” refer to USD Group LLC, a Delaware limited liability company and currently the sole direct subsidiary of USD; (iv) “Energy Capital Partners” refers to Energy Capital Partners III, LP and its parallel and co-investment funds and related investment vehicles; and (v) “Goldman Sachs” refers to The Goldman Sachs Group, Inc. and its affiliates.
Cautionary Note Regarding Forward-Looking Statements
This Annual Report includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Annual Report speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) the impact of the novel coronavirus (COVID-19) pandemic and related economic downturn and governmental regulations; (2) changes in general economic conditions; and commodity prices; (3) the effects of competition, in particular, by pipelines and other terminalling facilities; (4) shut-downs or cutbacks at upstream production facilities, refineries or other related businesses; (5) government regulations regarding oil production, including if the Alberta Government were to resume setting production limits; (6) the supply of, and demand for, terminalling services for crude oil and biofuels; (7) the price and availability of debt and equity financing; (8) actions by third parties, including customers, lenders, construction-related services providers and our sponsors; (9) hazards and operating risks that may not be covered fully by insurance; (10) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (11) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (12) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs or limit our operations; and (13) our ability to successfully identify and finance potential acquisitions and other growth opportunities. For additional factors that may affect our results, see Item 1A. Risk Factors included elsewhere in this Annual Report and our subsequently filed Quarterly Reports on Form 10-Q, which are available to the public over the internet at the website of the U.S. Securities and Exchange Commission, or SEC, (www.sec.gov) and at our website (www.usdpartners.com).
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GLOSSARY
The following abbreviations, acronyms and terms used in this Form 10-K are defined below:
API Gravity American Petroleum Institute Gravity
Bitumen A dense, highly viscous, petroleum-based hydrocarbon that is found in deposits such as oil sands
Diluent Refers to lighter hydrocarbon products such as natural gasoline or condensate that are blended with heavy crude oil to allow for pipeline transportation of heavy crude oil
Diluent Recovery Unit USD’s patented diluent recovery unit, or DRU, technology separates the diluent that has been added to raw bitumen in the production process
DRUbit™ 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
Ethanol A clear, colorless, flammable oxygenated liquid typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood, which is used in the United States as a gasoline octane enhancer and oxygenate
Heavy crude A crude oil with a low API Gravity characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel
Crude-by-rail The transportation of hydrocarbons, such as crude oil and ethanol, by rail, particularly through the use of unit trains
Legacy railcar A Department of Transportation, or DOT, Specification 111 railcar that does not comply with the Association of American Railroads (AAR) Casualty Prevention Circular (CPC) letter known as CPC-1232 which specifies requirements for railcars built for the transportation of certain hazardous materials, including crude oil and ethanol
Manifest train Trains that are composed of mixed cargos and often stop at several destinations
Oil sands Deposits of loose sand or partially consolidated sandstone that are saturated with highly viscous bitumen, such as those found in Western Canada
PADD III Petroleum Administration for Defense District consisting of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas
Throughput The volume processed through a terminal or refinery
Unit train Refers to trains comprised of up to 120 railcars and are composed of one cargo shipped from one point of origin to one destination


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RISK FACTOR SUMMARY
The following is a summary of the material factors that make an investment in our common units speculative or risky, all of which are more fully described below in the section titled Item 1A. Risk Factors. This summary should not be relied upon as an exhaustive summary of the material risks facing our business. You should consider the information set forth in the “Risk Factors” section and the other information contained in this annual report before investing in our securities.

The COVID-19 pandemic has adversely affected our ability to grow, and its ultimate effect on us cannot be predicted.
We depend on a limited number of customers for a significant portion of our revenues.
Our contracts are subject to renewal risks and reductions in volume commitments.
The lack of diversification of our assets and geographic locations could adversely affect us.
Our business is subject to the risk of a capacity overbuild of midstream infrastructure and the entrance of new competitors in the areas where we operate.
Adverse developments affecting the fossil fuel industry or drilling activity could cause a reduction of volumes transported through our terminals.
Any reduction in our or our customers’ ability to utilize third-party storage facilities, pipelines, railroads or trucks that interconnect with our terminals could negatively impact customer volumes and renewal rates at our terminals.
Increases in rail freight costs may adversely affect our results of operations.
Our business involves many hazards and operational risks, which may cause disruptions, expose us to significant liabilities and not be fully covered by insurance.
If we are unable to make acquisitions on economically acceptable terms our future growth would be limited.
Our right of first offer to acquire certain of USD’s assets and projects is limited and subject to uncertainty.
Growing our business by constructing new assets subjects us to construction risks.
Our intent to distribute a significant portion of our available cash could limit our ability to pursue growth projects and make acquisitions.
Our ability to make cash distributions is subject to risks, including that we may not have sufficient cash from operations to pay distributions.
Our general partner may modify or revoke our cash distribution policy at any time and our partnership agreement does not require us to pay any distributions at all.
Restrictions in our senior secured credit agreement could adversely affect us and our ability to make distributions.
Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
Our debt may limit our flexibility to obtain financing and to pursue other business opportunities.
We may issue additional units without unitholder approval, which would dilute unitholder interests.
Some of our customers’ operations are subject to cross-border regulation.
Changes in provincial royalty rates and drilling incentive programs in Canada could adversely affect the demand for our terminalling services.
Our business could be adversely affected if service on the railroads is interrupted or if more stringent regulations are adopted regarding railcar design or the transportation of crude oil by rail.
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We operate in a highly regulated industry, which may expose us to significant costs and liabilities.
Legislation, regulatory initiatives, litigation and investor sentiment relating to the oil and gas industry or climate change could have an adverse effect on us.
The credit and risk profile of our general partner could adversely affect our credit ratings and risk profile.
There are risks inherent in our master limited partnership ownership structure, including the limited duties owed to us and our unitholders by our general partner and limitations on its liability, potential conflicts between us and our general partner, and unitholders’ limited voting rights and inability to remove our general partner without its consent or prevent the transfer of our general partner to a third party.
The New York Stock Exchange does not require us to comply with certain of its corporate governance requirements.
Our status as a partnership for U.S. federal income tax purposes, or our ability to take certain of the positions we take for U.S. federal income tax purposes, may be successfully challenged or changed by law, by judicial interpretation, or by administrative action.
We are still required to pay non U.S. taxes and may be subject to significant federal, state and local taxes.
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Corporate income tax on our subsidiary, which is treated as a corporation for U.S. federal income tax purposes, reduces our cash available for distributions.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments we pay on such unitholders’ behalf.
Ownership of our common units is subject to certain tax-related risks, including that tax gain or loss on the disposition of our common units could be more or less than expected, certain actions that we may take may increase the U.S. federal income tax liability of unitholders, and there are limits on the deductibility of our losses by unitholders.
Tax-exempt entities and non-U.S. persons face potentially adverse tax consequences from owning our common units.
As a result of investing in our common units, you may become subject to state, local and foreign taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
Increases in interest rates could adversely affect us.
We may recognize impairment on long-lived assets and intangible assets.
Terrorist or cyber-attacks and threats could have a material adverse effect on us.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud.

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PART I
Item 1. Business
OVERVIEW
We are a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group LLC, or 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 and biofuels 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. On occasion we 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 commodity price exposure.
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. As the role of biofuels continues to expand in the clean energy transition, we are committed to offering new capabilities and services across growing demand in clean fuels to include ethanol, renewable diesel and biodiesel.
USD Group LLC, or 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. Also, USD, along with its joint venture partner, is pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada by constructing a diluent recovery unit, or DRU, near Hardisty, Alberta, Canada, as discussed below. USD believes the DRU project will maximize benefits to producers, refiners and railroads. Additionally, in January 2019, USDG completed an expansion project at the Partnership’s Hardisty Terminal, also referred to 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, and is subject to our existing right of first offer.
The following table summarizes information about our current terminalling facility assets:
Terminal Name Location Designed
Capacity
(Bpd)
Commodity
Handled
Primary
Customers
Terminal
Type 
Hardisty Terminal
Alberta, Canada
~150,000 (1)
Crude Oil Producers/Refiners
/Marketers
Origination
Casper Terminal
Wyoming, U.S.
~105,000 (2)
Crude Oil Refiners/Marketers Origination
Stroud Terminal Oklahoma, U.S.
~50,000 (3)
Crude Oil Producers Destination
West Colton Terminal California, U.S. 13,000 Ethanol Refiners/Blenders Destination
(1)Based on two 120-railcar unit trains comprised of 28,371 gallon (approximately 675.5 barrels, or bbls) railcars being loaded at 92% of volumetric capacity per day. Actual amount of crude oil loading capacity may vary based on factors including the size of the unit trains, the size, type and volumetric capacity of the railcars utilized and the type and specifications of crude oil loaded, among other factors.
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(2)Based on one and one-half 112-railcar unit trains comprised of 28,371 gallon (approximately 675.5 bbls) railcars being loaded at 92% of volumetric capacity per day. Actual amount of crude oil loading capacity may vary based on factors including the size of the unit train, the size, type and volumetric capacity of the railcars utilized and the type and specifications of crude oil loaded, among other factors.
(3)Our current Stroud Terminal capacity of approximately 50,000 Bpd includes pipeline pumping capacity constraints on the pipeline that is utilized to move crude oil between our Stroud Terminal storage tanks and third-party storage tanks at Cushing. With pump modifications, the 104-railcar unit train could unload up to 64,376 Bpd based on 28,371 gallon (approximately 675.5 bbls) railcars being unloaded at 92% of volumetric capacity per day. Actual amount of crude oil loading capacity may vary based on factors including the size of the unit train, the size, type and volumetric capacity of the railcars utilized and the type and specifications of crude oil unloaded, among other factors.
We offer our terminalling services pursuant to multi-year, take-or-pay agreements primarily with high quality, investment grade customers, which provides us with a steady and reliable stream of cash flows. Our agreements typically range in term between three and five years and include renewal options. However, upon the successful completion and commencement of USD’s DRU project, discussed below, certain of the terminalling services agreements at our Hardisty Terminal will automatically convert to 10 year agreements and extend through mid-2031. During 2019, we successfully renewed and extended multiple agreements on a long-term basis at our rail terminals. As of December 31, 2020, the volume-weighted average remaining contract life of our take-or-pay terminal service agreements was 2.6 years. Refer to the Business Segments section below for further information regarding our customer contracts for each of our rail terminals.
In addition to terminalling services, we currently provide customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on a multi-year, take-or-pay basis for periods ranging from five to nine years. In the aggregate, our master fleet services agreements have a weighted-average remaining contract life of 1.5 years as of December 31, 2020. 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.
We believe one of our key strengths is our relationship with our sponsor, USDG, the sole direct subsidiary of USD. USD was among the first companies to successfully develop the hydrocarbon-by-rail concept and has built or operated unit train-capable terminals with an aggregate capacity of over one million bpd. Ten of these terminals were subsequently sold in multiple transactions for an aggregate sales price in excess of $740 million. From January 2006 through December 2020, USD has loaded or handled through its terminal network a total of 340 million barrels, or MMbbls, of liquid hydrocarbons and biofuels. USD also has a nationally recognized safety record with no reportable spills at any of its terminals since its inception, as defined by the U.S. Department of Transportation, or DOT, Pipeline and Hazardous Materials Safety Administration, or PHMSA. USD is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD’s management team members.
In September 2014, Energy Capital Partners made a significant investment in USD and indicated an intention to invest an additional $1.0 billion of equity capital in USD, subject to market and other conditions, to support future growth and expansion plans. Energy Capital Partners, together with its affiliates and affiliated funds, is a private equity firm with over $20.0 billion in capital commitments that primarily invests in North America’s energy infrastructure. Energy Capital Partners has significant energy infrastructure, midstream, master limited partnership and financial expertise to complement its investment in USD. To date, Energy Capital Partners and its affiliated funds have 54 investment platforms with investments in the renewable and power generation, environmental infrastructure and midstream sectors of the energy industry.
USD, through its direct ownership of USDG, has stated that it intends for us to be its primary growth vehicle in North America. We intend to strategically expand our business by acquiring energy-related logistics assets related to the storage and transportation of liquid hydrocarbons and biofuels from both USDG and third parties. We also intend to grow organically by opportunistically pursuing growth projects and enhancing the profitability of our existing assets. We believe that our relationship with USD and its successful project development and operating history, safety track record and industry relationships provide us with many avenues to execute our growth strategy.
The following chart depicts a simplified organization and ownership structure as of December 31, 2020. The ownership percentages referred to below illustrate the relationships among us, our general partner, USDG, USD,
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Energy Capital Partners and Goldman Sachs, and excludes 1,437,322 phantom unit awards, or Phantom Units, outstanding under our Long-Term Incentive Plan at December 31, 2020.

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USDP-20201231_G1.JPG
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BUSINESS STRATEGY
Our primary business objective is to generate sustainable free cash flow to strengthen our financial position and prudently grow the quarterly cash distributions we make to our unitholders over time. We intend to accomplish this objective by executing the following business strategies:
•    Generate stable and predictable fee-based cash flows.    A substantial amount of the operating cash flow we expect to generate is attributable to multi-year, take-or-pay agreements. We intend to continue to seek stable and predictable cash flows by extending the term of our agreements with existing customers, as well as executing additional multi-year, take-or-pay agreements with existing and new customers across our terminal network.
•    Pursue accretive acquisitions.    We intend to pursue strategic and accretive acquisitions of energy-related logistics assets related to the storage and transportation of liquid hydrocarbons and biofuels from both USD and third parties. We regularly evaluate and monitor the marketplace to identify acquisitions and expansions that may be pursued independently or jointly with USD.
•    Pursue organic growth initiatives and expansions.    We intend to pursue organic growth opportunities and seek operational efficiencies that complement, optimize or improve the profitability of our assets. For example, as the role of biofuels continues to expand in the clean energy transition, we are committed to offering new capabilities and services across growing demand in clean fuels to include ethanol, renewable diesel and biodiesel. In addition, our Casper Terminal includes the foundation for two additional storage tanks, which if constructed, may result in additional long-term volume commitments and cash flows.
•    Maintain a conservative capital structure.    We intend to maintain a conservative capital structure which, when combined with our focus on stable, fee-based cash flows, should afford us access to capital at a competitive cost. Consistent with our disciplined financial approach, we intend to fund the capital required for expansion and acquisition projects through a balanced combination of equity and debt financing. We believe this approach provides us the flexibility to effectively pursue accretive acquisitions and organic growth projects as they become available.
•    Maintain safe, reliable and efficient operations.    We are committed to safe, efficient and reliable operations that comply with environmental and safety regulations. We strive to continually improve operating performance through our commitment to technologically-advanced logistics and operations systems, employee training programs and other safety initiatives and programs with railroads, railcar producers and first responders. All of our facilities currently meet or exceed applicable government safety regulations and are in compliance with recently enacted orders regarding the movement of liquid hydrocarbons and biofuels by rail. We believe these objectives are integral to the success of our business as well as to our access to growth opportunities.
BUSINESS SEGMENTS
We conduct our business through two distinct reporting segments: Terminalling services and Fleet services.
These segments have unique business activities that require different operating strategies. For information relating to revenues from external customers, operating income or loss and total assets for each segment, refer to Note 15. Segment Reporting of our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report. For information relating to revenues from material customers, refer to Note 17. Major Customers and Concentration of Credit Risk of our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.
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. These services are primarily provided under multi-year, take-or-pay agreements that include minimum monthly commitment fees. We generally have no direct exposure to risks associated with fluctuating commodity prices, although changes in crude oil prices could indirectly influence our activities and results of operations over the long term. We may on occasion enter into buy-sell and other arrangements in which we take temporary title to
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commodities while held in our terminals. We expect any such agreements to be at fixed prices where we do not take commodity price exposure.
Our Terminalling services business consists of the following operations:
Hardisty Terminal
Our Hardisty Terminal, which commenced operations in June 2014, is an origination terminal where we load various grades of Canadian crude oil onto railcars for transportation to end markets. Hardisty is one of the major crude oil hubs in North America and is an origination point for approximately 90% of the export pipeline capacity to the United States. At the Partnership level, the 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. The terminal is also equipped with an onsite vapor management system that allows our customers to minimize hydrocarbon loss while improving safety during the loading process. Our Hardisty Terminal receives inbound deliveries of crude oil through a direct pipeline connection from Gibson Energy Inc.’s, or Gibson’s, Hardisty storage terminal. Gibson is one of the largest independent midstream companies in Canada with 13.5 MMbbls of crude oil storage facilities at Hardisty plus the greatest number of connections to inbound and outbound pipelines in the Hardisty hub. Our Hardisty Terminal’s strategic location and direct pipeline connection to substantial storage capacity provides efficient access to the major producers in the region. Our Hardisty Terminal is also connected to the Canadian Pacific Railway’s North Main Line, a high capacity line with the ability to service key refining markets across North America.
We have a facilities connection agreement with Gibson under which Gibson operates and maintains a 24-inch diameter pipeline and related facilities connecting Gibson’s storage terminal with our Hardisty Terminal, which we operate and maintain. Gibson is responsible for transporting product through the pipeline to our Hardisty Terminal. This pipeline from Gibson’s storage terminal is the exclusive means by which our Hardisty Terminal receives crude oil. Subject to certain limited exceptions regarding manifest train facilities, our Hardisty Terminal is also the exclusive means by which crude oil from Gibson’s Hardisty storage terminal may be transported by rail. We remit pipeline fees to Gibson for the transportation of crude oil to the Hardisty Terminal based on a predetermined formula. The facilities connection agreement also gives Gibson a right of first refusal in the event of a sale of our Hardisty Terminal to a third party. The agreement will expire in 2034 unless renewed. Our and Gibson’s obligations under this facilities connection agreement may be suspended in the case of a force majeure event. Additionally, the agreement may be terminated by the non-defaulting party in case of specified events of default.
Substantially all of the capacity at our Hardisty Terminal is contracted under multi-year, take-or-pay terminal services agreements with four customers, including major integrated oil companies, refiners and marketers. To date, we have renewed and extended 100% of the capacity at our Hardisty Terminal through mid-2022, with 73% extended through mid-2023 with customers under multi-year take-or-pay agreements. Upon the successful completion of USD’s Diluent Recovery Unit project discussed below, 32% of the Hardisty Terminal’s capacity will be automatically extended through mid-2031.
Our terminal services agreements generally include automatic renewal provisions for periods up to one-year following the conclusion of the initial term and will only terminate if written notice is given by either party within a specified time period before the end of the initial term or a renewal term. Most of our terminal services agreements contain annual inflation-based rate escalators based upon the consumer price index of either Canada or Alberta. If a force majeure event occurs, a customer’s obligation to pay us may be suspended, in which case the length of the contract term will be extended by the same duration as the force majeure event. We will not be liable for any losses of crude oil handled at our Hardisty Terminal unless due to our negligence.
Under the terminal services agreements we have entered into with customers of our Hardisty Terminal, our customers are obligated to pay the greater of a minimum monthly commitment fee or a throughput fee based on the actual volume of crude oil loaded at our Hardisty Terminal. If a customer loads fewer unit trains or barrels than its allotted amount in any given month, that customer will receive a credit for up to 12 months, which may be used to offset fees on throughput volumes in excess of its minimum monthly commitments in future periods, to the extent capacity is available for the excess volume.
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Sponsor and USDs Initiatives at Hardisty
USDs Diluent Recovery Unit Project
In December 2019, USD and Gibson jointly announced an agreement to construct and operate a diluent recovery unit, or DRU, near Hardisty, Alberta, Canada. A subsidiary of ConocoPhillips has contracted to process 50,000 barrels per day of inlet bitumen blend through the DRU to be shipped by Canadian Pacific Railway and Kansas City Southern Railway Company to the Port Arthur Terminal, or PAT, to be constructed by USD, on the U.S. Gulf Coast. In February 2020, USD and Gibson jointly announced the receipt of all required regulatory approvals from the Government of Alberta to proceed with the construction of a DRU. Additionally, USD and Gibson have finalized all required commercial agreements with a subsidiary of ConocoPhillips to fully underpin and sanction the construction of the initial phase of the DRU at 50,000 barrels per day of inlet bitumen blend capacity and enable rail shipments of DRUbit™ to the U.S. Gulf Coast.
Construction of the DRU and PAT have commenced and USD expects they will be placed into service late in the second quarter or early in the third quarter of 2021. USD has secured the necessary financing, obtained all material permits and entered into fixed-price construction contracts regarding the construction of the project. USD and Gibson are currently in commercial discussions with other potential producer and refiner customers to secure additional long-term, take-or-pay agreements to support future expansions of capacity at the DRU.
USD’s patented DRU process is designed to separate the diluent that is added to raw bitumen in the production process in order to meet 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 U.S. DRUbit™ is a market access solution designed to 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 diluted bitumen crude oil that is transported by pipeline today.
As mentioned, USD is constructing a new destination terminal in Port Arthur, Texas for the DRUbit™ that will be transloaded at our Hardisty Terminal. USD’s Port Arthur Terminal, or PAT, will have the capability for rail unloading, barge dock loading and unloading, tank storage and blending and will be pipeline connected to Phillips 66’s Beaumont Terminal, providing customers access to a large network of refining and marine facilities. The facility will be set up to handle DRUbit™, diluent bitumen, or Dilbit, and a heavy Canadian conventional barrel and manage the blending of DRUbit™ into a marketable product for shippers. The marine and pipeline delivery options for blended products at the terminal will allow customers to enhance market flexibility and take advantage of cost advantaged delivery options. PAT will be served by the Kansas City Southern railroad and sits on exclusive rail infrastructure, providing seamless scheduling, operations, and communications resulting in ratable and reliable service. Within the 233-acre terminal footprint, there is ample waterfront and upland acreage that allows PAT expansion capabilities to accommodate any foreseeable demand.
We believe the PAT project is well positioned in a market poised for growth. The Port Arthur market is home to over 1.6 million barrels of refining capacity per the EIA and a growing petrochemical market. With ExxonMobil’s 250,000 barrel per day refinery expansion expected to be in service in 2023, and Motiva’s acquisition of the Flint Hills ethane cracker dovetailing into planned downstream expansions into the petrochemical market, Port Arthur’s heavily utilized midstream infrastructure can expect liquid volumes to increase.
Within the Port Arthur market, PAT will be well positioned to take advantage of these opportunities and other organic growth projects. Pipeline connectivity to the hub of Port Arthur’s liquids business provides an advantage through reduced costs to deliver crude locally relative to a barge alternative and will extend the market reach for customers of PAT. Customers of PAT will be able to deliver barrels by pipeline and water into Louisiana markets when the terminal goes into service. It is expected that customers of PAT will also be able to deliver into Houston in the future, as a pipeline connection project is currently under construction and is expected to be placed into service by 2022. USD’s Port Arthur Terminal would also be available for possible acquisition by the Partnership, and would
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be subject to the Partnership’s right of first offer on USD’s assets pursuant to the omnibus agreement between USD and the Partnership, or Omnibus Agreement, which extends through October 15, 2021.

Management believes that the successful completion of USD’s DRU project will enhance the sustainability and quality of our cash flows at the Partnership by significantly increasing the average tenor of three terminalling services agreements at our Hardisty Terminal through 2031. Expirations and renewals for some of our terminalling services agreements at our Hardisty and Stroud Terminals will depend on whether USD’s DRU project and construction of the Port Arthur terminal discussed above, will be successful. For instance, with respect to three terminalling services agreements at our Hardisty Terminal, upon the successful completion and commissioning of the DRU project and Port Arthur terminal, all three terminalling services agreements will extend through mid-2031, with two-thirds of the volume commitment for one of these agreements terminating at the end of June 2022. If the DRU project is not completed, all three agreements at our Hardisty Terminal will expire in June 2024 (rather than in 2031), with two-thirds of the volume commitment for one agreement expiring in June 2022. USD’s interest in the Hardisty DRU project would also be available for possible acquisition by the Partnership, and would be subject to the Partnership’s right of first offer on USD’s assets pursuant to the Omnibus Agreement between USD and the Partnership.
The timing and commencement of the DRU and Port Arthur projects will impact the amount of volume commitments at the Stroud Terminal. Upon the commencement of the DRU and Port Arthur projects prior to June 30, 2022, we expect the customer to elect to reduce the volume commitments at the Stroud Terminal attributable to the Partnership (and move commitments to the DRU) by one-third of the current commitment through June 30, 2022, at which point the agreement will terminate and there will be no renewal period. We also expect the customer to elect to fully terminate the volume commitments attributable to USDM. If the DRU and Port Arthur projects have not commenced prior to June 30, 2022, on a net basis after giving effect to the USDM volumes that will be assigned to the Partnership, the volume commitments at the Stroud Terminal attributable to the Partnership will remain the same and extend through June 30, 2024. Approximately one-third of the volume commitments attributable to USDM will also extend through June 30, 2024 and the remaining volume commitments attributable to USDM will terminate on June 30, 2022. Management believes that the lower utilization at the Stroud Terminal as a result of successful completion of the DRU project will be short-term in nature and will allow the Partnership the opportunity to offer terminalling services to other customers in need of access to the numerous markets connected to the Cushing oil hub.
Hardisty South Expansion
Our sponsor completed the Hardisty South expansion (“Hardisty South”) in January 2019. The existing Hardisty Terminal, which is owned by us, has designed capacity for two unit trains per day, or approximately 150,000 barrels per day. Hardisty South, which is owned by our sponsor, added one and one-half unit trains per day, or approximately 112,500 barrels per day, of takeaway capacity to the terminal by modifying the existing loading rack and building additional infrastructure and trackage. We believe the Hardisty South Expansion could present an attractive acquisition opportunity for us pursuant to our existing right of first offer with respect to midstream projects developed by our sponsor.
Stroud Terminal
Our Stroud Terminal, which we purchased in June 2017, is a crude oil destination terminal in Stroud, Oklahoma. We use the terminal to facilitate rail-to-pipeline shipments of crude oil from our Hardisty Terminal in Western Canada 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. We have also secured 300,000 bbls of crude oil tank storage at the Cushing hub to facilitate outbound shipments of crude oil from the Stroud Terminal. Inbound product is delivered by the Stillwater
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Central Rail, which handles deliveries from both the BNSF Railway, or BNSF, and the Union Pacific Railroad, or UP.
Our Stroud Terminal is the only rail facility connected to the Cushing storage hub, which provides for strategic and competitive advantages. The benchmark price in the domestic spot market for U.S. crude oil known as West Texas Intermediate, or WTI, is set at the Cushing hub. According to the EIA, the Cushing storage hub has approximately 76 million barrels of working storage capacity. There is also an expansive pipeline infrastructure that connects into and out of the Cushing hub. Because of the vast connectivity that Cushing offers, crude oil that is delivered into Cushing can then be delivered to either local refineries or it can be shipped to other markets such as the United States Gulf Coast, which is the largest refinery complex in the U.S. As such, 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.
Concurrent with the Stroud acquisition, we entered into a multi-year, take-or-pay terminalling services agreement with ConocoPhillips for the use of approximately 50% of the available capacity at the Stroud Terminal. Our customer is obligated to pay a minimum monthly commitment fee and can load an allotted number of barrels per month. If our customer loads fewer barrels than its allotted amount in any given month, the customer will receive a credit for up to 12 months. This credit may be used to offset fees on throughput volumes in excess of our customer’s minimum monthly commitments in future periods to the extent capacity is available for the excess volume. We will receive a per-barrel fee on any volumes handled in excess of our customer’s allowed amount, to the extent the additional volume is not subject to the credit discussed above. Upon the successful completion of USD’s Diluent Recovery Unit project discussed above, our Stroud customer will have the right to terminate their agreement at our Stroud Terminal in June 2022.
In addition, we entered into a Marketing Services Agreement, or MSA, in May 2017, with USD Marketing LLC, or USDM, a wholly-owned subsidiary of USDG, whereby we granted USDM the right to market the capacity at the Stroud Terminal in excess of the original capacity of our initial customer in exchange for a nominal per barrel fee. USDM is obligated to fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional throughput. Upon expiration of our contract with the initial Stroud customer in June 2020, the same marketing rights now apply to all throughput at the Stroud Terminal in excess of the throughput necessary for the Stroud Terminal to generate adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud customer during the 12 months prior to expiration. We also granted USDG the right to develop other projects at the Stroud Terminal in exchange for the payment to us of market-based compensation for the use of our property for such development projects. Our sponsor is also evaluating a potential expansion of the Stroud Terminal to meet incremental demand. If successful, these efforts would provide us with cash flows incremental to those provided by our currently-contracted capacity. Any such development projects would be wholly-owned by USDG and would be subject to our existing right of first offer with respect to midstream projects they develop.
Casper Terminal
The Casper Terminal, which we acquired in November 2015, is a crude oil storage, blending and railcar loading terminal located in Casper, Wyoming, where the Express pipeline from Western Canada (~280,000 bpd of capacity) interconnects with the Platte Pipeline to Wood River, Illinois (~145,000 bpd of capacity). The Casper Terminal currently offers six storage tanks with 900,000 bbls of total capacity, unit train-capable railcar loading capacity of approximately 100,000 bpd, as well as truck transloading capacity. The terminal’s approximately 300-acre footprint and modular design allow for the addition of a second loading station and an additional 1.1 MMbbls of storage capacity with minimal disruption to existing operations and relatively low incremental capital costs.
Inbound crude oil is delivered to the Casper Terminal primarily through our dedicated 24-inch diameter, six-mile direct pipeline connection from the Express pipeline, which provides our customers with access to multiple grades of Canadian crude oil. 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. The Casper Terminal can also receive volumes through one truck unloading station and is also equipped with one truck loading station. Inbound volumes are typically fed directly into the customer’s dedicated storage tank(s), which enhances their ability to control the
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quality of the product from origin to end market. This also allows customers to blend multiple grades of crude oil to optimize the economics associated with refining varying grades of crude oil.
Outbound crude oil from our Casper Terminal is loaded onto railcars and is then transported to end markets by BNSF, in either manifest or unit train shipments. The terminal’s location on BNSF’s main line offers advantageous transportation costs to key U.S. refining markets where several customer-preferred destinations are also served by BNSF. Shipping with a single Class 1 railroad reduces railroad switching fees and enables faster train turn-times, thus improving railcar fleet utilization. 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.
In July 2019, Enbridge Inc. (“Enbridge”) announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of drag reducing agent, or DRA, and pump stations. We anticipate that some of the additional volumes resulting from the increased capacity on the Express pipeline could be delivered to our Casper Terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity. In late July 2020, Enbridge announced that it had placed 25,000 bpd of the additional capacity on its Express pipeline into service and plans to place the additional 25,000 bpd into service in 2021.
We provide service at the Casper Terminal under terminalling services agreements with a high quality, investment grade multi-national customer and a marketer customer. The multi-year agreements with these customers contain take-or-pay terms for terminalling and storage services and variable fees associated with actual throughput volumes and other services. Additionally, we may on occasion utilize our available storage and throughput capacity to support our customers’ spot activity through buy-sell agreements that generate cash flows in addition to those provided by our multi-year agreements.
West Colton Terminal
Our West Colton Terminal, completed in November 2009, is a unit train-capable destination terminal that can transload up to 13,000 bpd of ethanol 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. Our terminal receives inbound deliveries exclusively by rail on the UP high speed lines.
Due to corrosion concerns unique to biofuels such as ethanol, the long-haul transportation of biofuels by multi-product pipelines is less efficient and less economical than transportation by rail. We believe these corrosion concerns, combined with the proximity of our terminals to local demand markets, strategically position our terminal to benefit from anticipated changes in environmental and gasoline blending regulations that are expected to increase the use of ethanol in the market for transportation fuel.
We receive fixed fees per gallon of ethanol transloaded at our terminal pursuant to a terminal services agreement with a subsidiary of an investment grade company. Our West Colton Terminal operates under a minimum monthly commitment fee agreement that has been in place since July 2009 and is terminable at any time by either party upon 150 days’ notice.
Fleet Services
We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on a multi-year, take-or-pay basis under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of December 31, 2020, our railcar fleet consisted of 1,432 railcars, which we leased from various railcar manufacturers and financial entities, including 1,058 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet services agreements for 1,232 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars. Substantially all of our current railcar fleet is dedicated to customers of our Hardisty Terminal, including USDM. In the aggregate, our master fleet services agreements have a weighted-average remaining contract life of 1.5 years as of December 31, 2020.
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Under the master fleet services agreements, 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 customers typically pay us and our assignees monthly fees per railcar for these services, which include a component for fleet services.
All of our railcars currently in service were constructed in 2013 or later. The average age of our fleet currently in service is 6.6 years, as compared with the estimated 50-year life associated with these types of railcars. We have partnered with leaders in the railcar supply industry, such as CIT Rail, Union Tank Car Company and others. We believe that our relationships with these industry leaders enable us to obtain railcar market insight and to procure railcars for our terminalling customers on beneficial terms, with shorter lead times than some of our competitors. Our current railcars are designed at a minimum to be compliant with all regulatory railcar standards currently in effect.
As of December 31, 2020, our railcar fleet consisted of a mix of 1,058 C&I railcars and 374 non-coiled, non-insulated railcars. Our C&I railcars can reheat heavy viscous grades of crude oil, reducing the need to blend these heavier grades with diluents.
Historically we have 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.
BENEFITS OF RAIL
We believe that the following benefits of rail have established, or have the potential to establish, rail as a preferred mode of transportation for crude oil, biofuels, and other energy-related products:
Market access for areas without adequate pipeline transportation infrastructure. Certain producing regions, such as the Western Canadian oil sands, have concentrated production in areas without adequate existing pipeline takeaway capacity. The extensive existing rail infrastructure network provides additional takeaway capacity for these producing regions and flexible access to multiple demand centers.
Faster deployment. Rail terminals can be constructed at a fraction of the time required to lay a long-haul pipeline, providing a timely solution to meet new and evolving market demands. Relative to rail, new pipeline construction faces challenges such as lengthier build times and more extensive environmental permitting processes, geographic constraints and, in some cases, the lack of required political and regulatory support.
Flexibility to deliver to different end markets. Unlike pipelines, which typically transport product to a single demand market, rail offers customers access to many of the most advantageous demand centers throughout North America, enabling producers and shippers to obtain competitive prices for their products and to retain the flexibility to determine the ultimate destination until the time of transportation.
Comprehensive solution for refiners. Rail provides refiners flexible access to multiple qualities and grades of crude oil (feedstock) from multiple production sources. Additionally, shipping in railcars improves the customer’s ability to preserve the specific quality of the product over long distances relative to pipelines.
Faster delivery to demand markets. Rail can transport energy-related products to end markets much faster than pipelines, trucks or waterborne tankers. While a pipeline can take 30-45 days to transport crude oil to the Gulf Coast from Western Canada, unit trains can move crude oil along a similar path in approximately nine days.
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Reduced shipper commitment requirements. Whereas all of the pipeline transportation fee is typically subject to long-term shipper commitments, only a portion of rail transportation costs require long-term shipper commitments (railroads have historically been contracted on a spot basis or only require partial term commitments). Consequently, pipeline customers bear greater risk of shifts in regional price differentials and the location of demand markets.
Reduced shipper transportation cost. Rail provides shippers a competitive transportation option, particularly in situations where either (i) the amount of diluent required for the transportation of crude oil by pipeline is high, which is generally the case for production from the Canadian oil sands, or (ii) multiple modes of transportation are required to reach a particular end market.
RIGHT OF FIRST OFFER
In connection with our initial public offering, or IPO, we entered into the Omnibus Agreement with USD and USDG, pursuant to which we were granted a right of first offer on any midstream infrastructure assets that they may develop, construct, or acquire for a period of seven years after the closing of our IPO, which occurred on October 15, 2014. This right expires on October 15, 2021. Additional information about the Omnibus Agreement and the right of first offer are included in Note 13. Transactions with Related Parties of our consolidated financial statements at Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
USD has not engaged in any transactions that implicate our right of first offer. We cannot assure you that USD will be able to develop or construct, or that we or USD will be able to acquire, any additional midstream infrastructure projects. Among other things, the ability of USD to further develop the Hardisty Terminal and Stroud Terminal, the DRU project, or any other project, and our ability to acquire such projects, will depend upon USD’s and our ability to raise additional equity and debt financing. We are under no obligation to make any offer, and USD and USDG are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer. Additionally, the approval of Energy Capital Partners is required for the sale of any assets by USD or its subsidiaries, including us (other than sales in the ordinary course of business), acquisitions of securities of other entities that exceed specified materiality thresholds and any material unbudgeted expenditures or deviations from our approved budgets. Energy Capital Partners may make these decisions free of any duty to us and our unitholders. This approval would be required for the potential acquisition by us of any project to expand the Hardisty Terminal and Stroud Terminal, as well as any other projects or assets that USD may develop or acquire in the future or any third-party acquisition we may pursue independently or jointly with USD. Energy Capital Partners is under no obligation to approve any such transaction. Please refer to the discussion under Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners regarding the rights of Energy Capital Partners. If we are unable to acquire any projects to expand the Hardisty Terminal and Stroud Terminal from USD, such expansions may compete directly with our existing business for future throughput volumes, which may impact our ability to enter into new terminal services agreements, including with our existing customers, following the expiration of our existing agreements, or the terms thereof, and our ability to compete for future spot volumes. Furthermore, cyclical changes in the demand for crude oil and other liquid hydrocarbons may cause USD, or us, to further re-evaluate any future expansion projects, including expansion of the Hardisty Terminal and Stroud Terminal.
COMPETITION 
The energy-related logistics infrastructure business is highly competitive. The ability to secure additional agreements for rail terminalling and railcar fleet services is primarily based on the availability of alternative means of transportation, primarily pipelines, as well as the reputation, efficiency, flexibility, location, market economics and reliability of the services provided and pricing for those services.
Our crude oil terminals face competition from other logistics services providers, such as pipelines and other terminalling service providers. In addition, our customers may also choose to construct or acquire their own terminals. If our customers choose to ship crude oil via alternative means, we may only receive the minimum monthly commitment fees at our terminals and may be unable to renew, extend or replace customer agreements following expiration of their terms. Our West Colton Terminal business faces competition from other terminals and
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trucks that may be able to supply end-user markets with ethanol and other biofuels on a more competitive basis due to terminal location, price, rail rates, versatility or services provided. The West Colton Terminal is served by the UP and competes directly with ethanol facilities in the Fontana, Carson and San Diego areas, which are served by the BNSF Railway. A combination of rail freight and trucking economics, which comprise the largest share of the value chain, make it very difficult to compete with other facilities in this market based on terminalling throughput fees alone.
We believe that we are favorably positioned to compete in our industry due to the strategic location of our terminals, quality of service provided at our terminals, our independent strategy, our reputation and industry relationships, and the versatility and complementary nature of our services. The competitiveness of our service offerings could be significantly impacted by the entry of new competitors into the markets in which we operate. However, we believe that significant barriers to entry exist in the energy-related logistics business. These barriers include significant costs and execution risk, a lengthy permitting and development cycle, financing challenges, shortage of personnel with the requisite expertise, and a finite number of sites suitable for development.
SEASONALITY
The amount of throughput at our terminals is affected by the level of supply and demand for crude oil, refined products and biofuels, as well as, to a lesser extent, seasonality. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and construction work. Production in Western Canada may be impeded by severe winter conditions that reduce production and volumes. However, many effects of seasonality on our revenues are substantially mitigated due to our terminal service agreements with our customers that include minimum monthly commitment fees, as well as our master fleet services agreements which require our customers to pay a base monthly fee per railcar. Furthermore, because there are multiple end markets for the crude oil and biofuels handled at our terminals, the effect of seasonality otherwise attributable to one particular end market is mitigated.

IMPACT OF REGULATION
General
Our operations are subject to complex and frequently-changing federal, state, provincial and local laws and regulations regarding the protection of health, property and the environment, including laws and regulations that govern the handling and release of crude oil and other liquid hydrocarbon materials. Compliance with existing and anticipated environmental and safety laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate, and upgrade equipment and facilities. While these laws and regulations may affect our maintenance capital expenditures and net income or loss, customers typically place additional value on utilizing established and reputable third-party providers to satisfy their terminalling and logistics needs. As a result, we expect increased regulations to provide opportunities for us to increase our market share in relation to customer-owned operations or smaller operators that lack an established track record of safety and environmental compliance.
Violations of environmental or safety laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties, permit modifications or revocations, and in some instances, operational interruptions or injunctions banning or delaying certain activities. We believe our facilities are in substantial compliance with applicable environmental and safety laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state, provincial and local levels, and the legislative and regulatory trend has been to place increasingly stringent limitations on activities that may affect the environment.
Our operations contain risks of accidental releases into the environment, such as releases of crude oil, ethanol or hazardous substances from our terminals. To the extent an event is not covered by our insurance policies, such accidental releases could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental or safety laws or regulations.
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Air Emissions
Our operations are subject to and affected by the Clean Air Act, or CAA, and its implementing regulations, as well as comparable state and local statutes and regulations. Our operations are subject to the CAA’s permitting requirements and related emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. We are currently required to obtain and maintain various construction and operating permits under the CAA and have incurred capital expenditures to maintain compliance with all applicable federal and state laws regarding air emissions. We may, nonetheless, be required to incur additional capital expenditures in the near future for the installation of certain air pollution control devices at our terminals when regulations change, when we add new equipment, or when we modify our existing equipment. Our Canadian operations are similarly subject to federal and provincial air emission regulations.
Our customers are also subject to, and similarly affected by, environmental regulations restricting air emissions. These include U.S. and Canadian federal and state or provincial actions to develop programs for the reduction of greenhouse gas, or GHG, emissions such as proposals to create a cap-and-trade system that would require companies to purchase carbon dioxide emission allowances for emissions at manufacturing facilities and emissions caused by the use of the fuels sold. In addition, the U.S. Environmental Protection Agency, or EPA, and the federal Bureau of Land Management, or BLM, has begun to regulate emissions of carbon dioxide and other GHGs. As a result of these regulations, our customers could be required to undertake significant capital expenditures, operate at reduced levels, and/or pay significant penalties. These regulations’ impact on our oil and natural gas exploration and production customers could result in a decreased demand for the services that we provide. We are uncertain what our customers’ responses to these emerging issues will be. Those responses could reduce throughput at our terminals, as well as impact our cash flows and our ability to make distributions or satisfy debt obligations.
Climate Change
Following its December 2009 “endangerment finding” that GHG emissions pose a threat to public health and welfare, the Environmental Protection Agency, or EPA, has begun to regulate GHG emissions under the authority granted to it by the federal CAA. Based on these findings, the EPA has adopted regulations under existing provisions of the federal CAA that require Prevention of Significant Deterioration, or PSD, pre-construction permits and Title V operating permits for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities and, starting in October 2015, onshore petroleum and natural gas gathering and boosting activities as well as natural gas transmission pipelines. We believe we are in substantial compliance with all GHG emissions permitting and reporting requirements applicable to our operations.
In response to studies suggesting that emissions of CO2, methane and certain other gases may be contributing to warming of the Earth’s atmosphere, over 190 countries, including the United States and Canada where we operate, committed to a legally binding treaty to reduce GHG emissions, the terms of which were defined at the Paris climate conference in December 2015. The terms of the Paris treaty to reduce GHG emissions became effective in 2020. In November 2019, the Trump administration moved to exit the Paris treaty and formally exited the agreement in November 2020; however, in January 2021 the Biden Administration announced that the U.S. would be re-entering the agreement. With regard to the oil and gas industry, it is unclear at this time what direction the government of the United States plans to take. However, President Biden and the Democratic Party, which now controls Congress, have identified climate change as a priority, and it is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, delaying or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. For example, the acting Secretary of the Department of the Interior recently issued an order preventing staff from producing any new fossil fuel leases or permits without sign-off from a top political appointee, and President Biden
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recently announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden’s order also established climate change as a primary foreign policy and national security consideration, affirms that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirms President Biden’s desire to establish the United States as a leader in addressing climate change generally further integrates climate change and environmental justice considerations into government agencies’ decision making, and eliminates fossil fuel subsidies, among other measures. Additionally, some U.S. states are taking measures to reduce GHG emissions. For example, a coalition of over 20 governors of U.S. states formed the United States Climate Alliance to advance the objectives of the Paris treaty, and several U.S. cities have committed to advance the objectives of the Paris treaty at the state or local level despite the federal withdrawal. Increased costs associated with compliance with any future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows. In addition, climate change legislation and regulations may result in increased costs not only for our business but also for our customers, thereby potentially decreasing demand for our services. Decreased demand for our services may have a material adverse effect on our results of operations, financial condition and cash flows. Finally, many scientists believe that increasing concentrations of GHGs in the Earth’s atmosphere produce climate changes that can have significant physical effects, such as increased frequency and severity of storms, droughts and floods, as well as other climatic events. If any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and results of operations.
Waste Management and Related Liabilities
To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.
Site Remediation.    The federal Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as CERCLA or the Superfund law, and comparable state laws impose liability without regard to fault or to the legality of the original conduct on certain classes of persons regarding the presence or release of a “hazardous substance” in (or into) the environment. Those persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substance found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. CERCLA also authorizes the EPA and, in some instances, third parties, to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Claims filed for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment are not uncommon from neighboring landowners and other third parties. Petroleum products are typically excluded from CERCLA’s definition of “hazardous substances.” In the ordinary course of operating our business, we do not handle wastes that are designated as hazardous substances and, as a result, we have limited exposure under CERCLA for all or part of the costs required to clean up sites at which hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on our maintenance capital expenditures and operating expenses to the extent not covered by insurance. Canadian and provincial laws also impose liabilities for releases of certain substances into the environment.
We currently own or lease properties where hydrocarbons are currently handled or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where these wastes have been taken for disposal. These properties and wastes disposed thereon may be subject to CERCLA, the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state and Canadian federal and provincial laws and regulations. Under these laws and regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination. We have
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not been identified by any state or federal agency as a Potentially Responsible Party under CERCLA in connection with the transport and/or disposal of any waste products to third-party disposal sites. We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. Our insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to certain pollution events, including gradual pollution or sudden and accidental occurrences.
Solid and Hazardous Wastes.    Our operations generate solid wastes, including some hazardous wastes, which are subject to the requirements of RCRA and analogous state and Canadian federal and provincial laws that impose requirements on the handling, storage, treatment and disposal of hazardous wastes. Many of the wastes that we generate are not subject to the most stringent requirements of RCRA because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations. Oil and gas wastes may be included as hazardous wastes under RCRA in the future, in which event our wastes as well as the wastes of our competitors will be subject to more rigorous and costly disposal requirements, resulting in additional capital expenditures or operating expenses.
Water
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, or CWA, and analogous state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States or into any type of water body in Canada, as well as state and provincial waters. Federal, state and provincial regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and comparable laws, in addition to requiring remedial action to clean up such water body and surrounding land. In June 2015, the EPA revised the definition of “waters of the United States,” or WOTUS, in a manner which was widely viewed as expanding the jurisdictional reach of all Clean Water Act programs. However, in September 2019 the EPA rescinded this rule and in January 2020 announced a revised rule clarifying the WOTUS definition. The revised rule became effective in June 2020 but is the subject of litigation challenges in multiple federal district courts. The District Court for the District of Colorado stayed the effective date of the revised rule only in the State of Colorado. The rule is being implemented by the EPA and the Army in all other U.S. states and jurisdictions.
The Oil Pollution Act of 1990, or OPA, amended certain provisions of the CWA, as they relate to the release of petroleum products into navigable waters. OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages, and certain other consequences of an oil spill. These laws impose regulatory burdens on our operations. We believe that we are in substantial compliance with applicable OPA requirements. State and Canadian federal and provincial laws also impose requirements relating to the prevention of oil releases and the remediation of areas affected by releases when they occur. We believe that we are in substantial compliance with all such federal, state and Canadian requirements.
Endangered Species Act
The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area. Similar protections are in place for bald and golden eagles under the Bald and Golden Eagle Protection Act and for migratory birds under the Migratory Bird Treaty Act.
Rail Safety
We facilitate the transport of crude oil and related products by rail in the United States and Canada. We do not own or operate the railroads on which crude oil carrying railcars are transported; however, we currently lease or
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manage a railcar fleet on behalf of our customers. Accordingly, we are indirectly subject to regulations governing railcar design and manufacture, and increasingly stringent regulations pertaining to the shipment of crude oil by rail.
High-profile accidents involving crude oil unit trains in Quebec, North Dakota, Virginia, West Virginia and Illinois have raised concerns about the environmental and safety risks associated with transporting crude oil by rail, and the associated risks arising from railcar design. In August 2013, the Federal Railroad Administration, or FRA, issued both an Action Plan for Hazardous Materials Safety and an order imposing new standards on railroads for properly securing rolling equipment. A proposed rule with regard to the latter was subsequently released in September 2014. In August 2013, the FRA and PHMSA began conducting inspections of crude oil carrying railcars from the Bakken formation to make sure cargo is properly identified to railroads and emergency responders. In February 2014, the DOT and transportation industry agreed to certain voluntary measures designed to enhance the safety of crude oil shipments by rail, which include lowering speed limits for crude oil trains traveling in high-risk areas, modifying routes to avoid such high-risk areas, increasing the frequency of track inspections, implementing improved braking mechanisms, and improving the training of certain emergency responders.
In February 2014, as amended and restated in March 2014, the DOT issued another order, immediately requiring all carriers who transport crude oil from the Bakken region by rail to ensure that the product is properly tested and classified in accordance with federal safety regulations, and further requiring that all crude oil shipments be designated in the two highest risk categories, effectively mandating that crude oil be transported in more robust railcars. Any person failing to comply with the order is subject to potential civil penalties up to $175,000 for each violation or for each day they are found to be in violation, as well as potential criminal prosecution. Similarly, in February 2014, the Canadian Department of Transport, which we refer to as Transport Canada, finalized new regulations requiring shippers and carriers of crude oil by rail to properly sample, classify, certify and disclose certain characteristics of the crude oil being shipped, and gave shippers and carriers six months to comply with these new regulatory procedures. In April 2014, the Canadian Minister of Transport, who oversees Transport Canada, announced a series of directives and other actions to address the Transportation Safety Board of Canada’s initial recommendations on rail safety. Effective immediately, Transport Canada prohibited the least crash-resistant and non-upgraded or retrofitted DOT-111 railcars from carrying dangerous goods. Additionally, Transport Canada ordered DOT-111 railcars used to transport crude oil and ethanol that are not compliant with required safety standards be phased out or retrofitted by May 2017. Retrofitted DOT-111 railcars are now permitted to be used only with respect to certain packing groups until May 2025. We currently provide railcar services for 1,432 railcars, all of which are compliant with this Canadian safety standard.
In May 2014, the DOT issued another order, immediately requiring railroads operating trains carrying more than one million gallons of Bakken crude oil to notify State Emergency Response Commissions regarding the estimated volume, frequency, and transportation route of those shipments. Also in May 2014, the FRA and PHMSA issued a joint Safety Advisory to the rail industry advising those shipping or offering Bakken crude oil to use railcar designs with the highest available level of integrity and to avoid using older legacy DOT-111 or CTC-111 railcars. In July 2014, Transport Canada adopted the CPC-1232 technical standards as the minimum safety threshold for railcars transporting dangerous goods after May 2017.
In May 2015, the DOT, in coordination with Transport Canada, finalized new rail safety rules. The final rule includes more stringent construction standards for rail tank cars constructed after October 1, 2015. The final rule also creates a new North American tank car standard known as the DOT Specification 117 (DOT-117) with thicker steel and redesigned bottom outlet valves, among other improvements, over the DOT-111 tank car. U.S. crude oil shippers had until January 1, 2018, to phase out or upgrade older DOT-111 tank cars, while Canadian shippers were required to phase DOT-111 cars out of crude oil service by May 1, 2017. The rule also requires companies hauling crude in the U.S. or Canada to retrofit or phase out non-jacketed CPC-1232 tank cars by April 1, 2020. In addition, the final rule includes mandates for using electronically controlled pneumatic braking systems and for performing routing analyses and makes permanent the provisions of an emergency order issued by DOT in April 2015 imposing a speed limit of 40 miles per hour (mph) in high-threat urban areas for crude oil trains containing at least one older-model tank car. The speed limit for all other crude-by-rail service will be restricted to 50 mph, in line with the speed limit railroads voluntarily adopted in 2013. The final rule requires offerors to develop and carry out sampling and testing programs for all unrefined petroleum-based products, including crude oil, and to certify that hazardous
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materials subject to the program are packaged in accordance with the test results, but does not require oil companies to process their products to make them less volatile before shipment.
In February 2019, PHMSA, in cooperation with the FRA, issued a Final Rule that requires railroads to develop and submit Comprehensive Oil Spill Response Plans for route segments traveled by High Hazard Flammable Trains, or HHFTs. This new rule applies to HHFTs that are transporting crude oil in a block of 20 or more loaded tank cars and trains that have a total of 35 loaded crude oil tank cars. It will require railroads to establish geographic response zones with personnel and equipment ready to respond in the event of an accident. It will also require railroads to identify the qualified individual responsible for each response zone, as well as the organization, personnel, and equipment capable of handling a worst-case discharge scenario. Lastly, it will require rail carriers to provide information about HHFTs to state and tribal emergency response commissions in accordance with the FAST Act of 2015, Fixing America’s Surface Transportation. The new regulations took effect on April 1, 2019. Railroads were required to submit response plans by August 27, 2019. PHMSA has two years to review and comment on these plans.
On August 23, 2019, the Department of Energy and Sandia National Laboratory published a study that investigated whether Bakken crude presents a unique safety hazard due to explosions. Sandia National Laboratory performed fire experiments to compare the burn rate, surface emissive power, flame height, and heat flux to an engulfed object of different types of oil. The crude oil samples used for the experiments were obtained from several U.S. locations, including “tight” oils from the Bakken region of North Dakota and Permian region of Texas, and a conventionally produced oil from the U.S. Strategic Petroleum Reserve stockpile. The results showed that there is no material difference in the explosive characteristics or burn rates between the petroleum samples, and that the vapor pressure of Bakken crude is not a statistically significant factor in affecting these outcomes. The maximum average surface emissive power for all crude oil samples were below the Center for Chemical Process Safety (CCPS) recommendation to use a value of 350 kW/m2 for thermal hazard evaluation. Thus, the results from this work do not support additional regulation of Bakken crude based on oil vapor pressure, which could have limited the ability to move Bakken crude via rail.
All of our fleet was manufactured in 2013 or later and has been constructed or retrofitted to comply with the DOT 117, the jacketed CPC-1232 standard, or the unjacketed CPC-1232 standard. As of December 31, 2020, we do not have any railcars that will require retrofitting to comply with the jacketed CPC-1232 rules since our customers have informed us that they intend to use these railcars for transporting diesel fuel, which does not require retrofitting. However, if the railcars require retrofitting due to the customers’ decision to use the railcars for transporting crude oil, as opposed to diesel fuel, and if DOT were to adopt more strict specifications for tank cars, it would likely result in increased difficulty and costs to obtain compliant cars after the applicable phase-out dates. While we might be able to pass some of these costs on to our customers, there might be additional costs that we cannot pass on to our customers. We are continuously monitoring the railcar regulatory landscape and remain in close contact with railcar suppliers and other industry stakeholders to stay informed of railcar regulation rulemaking developments. Given the current railcar design compliance requirements and timelines outlined in the most recent Transport Canada and DOT rules, we do not anticipate a material impact to our ability to transport crude oil under our existing contracts. If future rulemakings result in more stringent design requirements and compressed compliance timelines, then our ability to transport these volumes could be affected by a delay in the railcar industry’s ability to provide adequate railcar modification repair services. We may not have access to a sufficient number of compliant cars to transport the required volumes under our existing contracts. This may lead to a decrease in revenues and other consequences. DOT and Transport Canada have also required operators to take certain precautions relating to rail routing, and mandated reductions in train speed and the implementation of new braking technology, to address rail safety concerns. On February 16, 2020, the Minister of Transport Canada announced that the speed limit for key trains that carry 20 or more cars containing dangerous goods, such as petroleum crude oil, liquefied petroleum gas, gasoline and ethanol, is 35 mph in metropolitan areas and 40 mph in other areas where there are no track signals. For the high risk key trains, which are unit trains where tank cars are loaded with a single dangerous goods commodity moving to the same point of destination or trains that include any combination of 80 or more tank cars containing dangerous goods, the speed limit is 25 mph where there are no track signals and 30 mph for metropolitan areas unless it is in a non-signal territory where the speed limit will be 25 mph. We do not expect that this new regulation will have an immediate impact on our results of operations. However, it could reduce the
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number of train sets our customers are able to cycle through our Hardisty Terminal, which may adversely affect the ability of our customers to meet their minimum volume commitments. As a result, our customers may be unwilling to renew or extend their existing contracts at current volumes and rates.
 Certain of the railroads serving our terminals have in the past and are currently considering imposing tariffs, fees or other limitations on the utilization of older railcar designs. These tariffs, fees and limitations could have the effect of imposing limits on the use of railcars that are more stringent than current regulatory standards, and could reduce the size of the overall railcar fleet available to be loaded at our terminals and increase the costs of obtaining usable railcars. Similar to other industry participants, compliance with existing and any additional environmental laws and regulations, or the imposition of additional tariffs, fees or limitations on the transportation of crude oil in certain railcars or all railcars by the railroads, could increase our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities, or the costs of our customers, which may reduce the attractiveness of rail transportation and limit our ability to extend existing agreements or attract new customers. Our master fleet services agreements generally obligate our customers to pay for modifications and other required repairs to our leased and managed railcar fleet. However, we cannot assure that we will be able to successfully pass all such regulatory costs on to our customers.
The adoption of additional federal, state, provincial or local laws or regulations, including any voluntary measures by the rail industry regarding railcar design or crude oil and liquid hydrocarbon rail transport activities, or efforts by local communities to restrict or limit rail traffic involving crude oil, could affect our business by increasing compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows.
Crude Oil Pipeline Safety
In connection with our acquisition of the Casper Terminal and Stroud Terminal and related facilities, we became subject to regulation by the Federal Energy Regulatory Commission, or FERC, the DOT through PHMSA, as well as other federal, state and local laws and regulations relating to the operation of our dedicated crude oil pipelines, rates charged for transportation service, and protection of health, property and the environment. The transportation and storage of crude oil and refined petroleum products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our crude oil pipeline and related assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979, also known as the HLPSA. The HLPSA delegated to DOT the authority to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, also known as the PSA, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required that regulations be issued to define the term “gathering line” and that safety standards for certain “regulated gathering lines” be established, and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in High Consequence Areas, or HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, also known as the APSPA, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, also known as the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room
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management. We are also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 reauthorized the federal pipeline safety programs of PHMSA through September 2019. Congress is currently in the process of reauthorizing these safety programs and a bill to reauthorize these programs was approved by the U.S. Senate in August 2020 and remains subject to approval by the U.S. House of Representatives.
PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of hazardous liquids by pipeline, including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced or otherwise changed; pressure testing of new pipelines; operation and maintenance of pipeline systems, establishing programs for public awareness and damage prevention, and managing the operation of pipeline control rooms; protection of steel pipelines from the adverse effects of internal and external corrosion; and integrity management requirements for pipelines in HCAs. On January 13, 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule was to be six months from publication in the Federal Register, but it was never sent to the Office of the Federal Register by the new Presidential administration, and was therefore effectively withdrawn. The final rule addressed several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued new regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes. These new regulations were to become effective March 24, 2017. These regulations were also subject, however, to further review in connection with the transition of Presidential administrations. PHMSA released its final safety standards for hazardous liquid pipelines, as well as rules for gas transmission pipelines, including maximum allowable operating pressure (MAOP) reconfirmation (for pipelines constructed before 1970) and records rules in September 2019, which became effective July 1, 2020. Also in September 2019, PHMSA finalized enhanced emergency order procedures allowing the agency to issue an emergency order which may impose emergency restrictions, prohibitions, or other safety measures on owners and operators of gas or hazardous liquid pipeline facilities.
We monitor the structural integrity of our pipeline system through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing and direct assessment that conforms to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data integration effort to ensure that the greatest risk areas receive the highest priority for scheduling subsequent integrity assessments. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test, and record the effectiveness of these corrosion inhibiting systems.
Crude Oil Pipeline Rate Regulation
The rates we charge for use of our dedicated crude oil pipeline are subject to regulation by various federal, state and local agencies. FERC regulates the transportation of crude oil on our dedicated Casper and Stroud pipelines under the Interstate Commerce Act, or ICA, Energy Policy Act of 1992, or EPAct 1992, and the rules and regulations promulgated under those laws. FERC regulations require that rates charged by pipelines that provide transport services in interstate or foreign commerce for crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids be just and reasonable, not unduly discriminatory, and not confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their transportation rates and terms and conditions of service. Under the ICA, FERC or interested persons may challenge existing or changed rates or services. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. FERC may also order a pipeline to change its rates and may require a common
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carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.
EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules extended until March 17, 2017. The FERC has not taken any further action following the close of the comment period. While common carriers often use the indexing methodology to change their rates, common carriers may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates, and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling). A common carrier can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a common carrier can establish rates under settlement if agreed upon by all current shippers. We have used settlement rates for our dedicated crude oil pipelines. If we used cost-of-service rate making to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise.
In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On December 23, 2016, FERC issued an Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Credits. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes in which FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to FERC’s discounted cash flow methodology. FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. Further, FERC stated that it will incorporate the effects of the post-United Airlines policy changes and the Tax Cuts and Jobs Act of 2017 on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. On July 18, 2018, FERC dismissed requests for rehearing and clarification of the March 15, 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income
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tax costs. In connection with an appeal regarding the order, the United States Court of Appeals for the District of Columbia Circuit upheld FERC’s position.
Intrastate services provided by our pipeline are subject to regulation by the Wyoming Public Service Commission. This state commission uses a complaint-based system of regulation, both as to matters involving rates and priority of access. The Wyoming Public Service Commission could limit our ability to increase our rates or to set rates based on our costs or order us to reduce our rates and require the payment of refunds to shippers. FERC and state regulatory commissions generally have not investigated rates, unless the rates are the subject of a protest or a complaint. However, FERC, or a state commission, could investigate our rates on its own initiative or at the urging of a third party.
If our rate levels were investigated by FERC or a state commission, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs, including:
the overall cost of service, including operating costs and overhead;
the allocation of overhead and other administrative and general expenses to the regulated entity;
the appropriate capital structure to be utilized in calculating rates;
the appropriate rate of return on equity and interest rates on debt;
the rate base, including the proper starting rate base;
the throughput underlying the rate; and
the proper allowance for federal and state income taxes
If the FERC, or the Wyoming Public Service Commission, on their own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline and terminals located in Casper, Wyoming and Stroud, Oklahoma, may suffer.
Security
While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered in the U.S. Congress and by U.S. Executive Branch departments and agencies, including the U.S. Department of Homeland Security, or DHS, and we may become subject to such standards in the future. We have implemented our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on our operations and those of our customers.
Employee Safety
We are subject to the requirements of the U.S. federal Occupational Safety and Health Act, or OSHA, and comparable state and Canadian federal and provincial statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard and the Canadian Workplace Hazardous Materials Information System, or WHMIS, require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA in the United States and comparable state and Canadian federal and provincial requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

HUMAN CAPITAL RESOURCES     
We are managed and operated by the board of directors and executive officers of USD Partners GP LLC, our general partner. Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner. Our general partner and its affiliates have
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approximately 90 employees, approximately 55 of whom performed services for our operations during 2020. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.
Our general partner and its affiliates believe employees are among their most important resources and are critical to the continued success of their and our businesses. Our general partner and its affiliates are focused on attracting and retaining high quality talent by providing fair and market-competitive pay, which includes base pay as well as both short and long-term incentives. Our general partner and its affiliates also offer employees a competitive benefits package, which includes among others, health insurance, paid time off, and a 401(k) savings plan with employee contribution matching. During fiscal years 2020 and 2019, the voluntary attrition rate for employees that are employed by our general partner and its affiliates was less than 5%.
During 2020, in response to the COVID-19 pandemic, our general partner and its affiliates implemented safety protocols and new procedures to protect employees. These protocols included social distancing and other health and safety measures based on guidelines of public health authorities. In addition, modifications were made to the way we conduct many aspects of our business to reduce the number of in-person interactions. For much of the year employees worked remotely when they were able and meetings with third parties were conducted virtually where possible. In addition, plexiglass divisions were installed in open work areas and regular more thorough deep cleanings were instituted in all offices and at each terminal location. Our general partner determined not to implement workforce or salary reductions during 2020, and no workforce or salary reductions are currently expected. However, we cannot guarantee that such measures will not be required or implemented in the future.
In addition, our general partner has a long-standing relationship with Railserve, Inc., or Railserve, a Marmon/Berkshire Hathaway company, to provide operating services for our terminals. Railserve is responsible for providing operations services to the terminals according to the specific contracts. Railserve is one of the largest in-plant rail operating services company in North America. Railserve operates over 80 switching and/or transloading locations across Canada, the United States and Mexico in the agriculture/food processing, chemical/plastics, energy/refining, intermodal, manufacturing, and pulp and paper markets. Railserve has over 1,400 personnel and 180+ Railserve owned and maintained locomotives. Railserve is responsible for attracting, retaining, supervising, and compensating its employees who are located at our terminals. To date, Railserve has successfully met our requirements for staffing operations at our terminals.
INSURANCE
Our rail terminals, pipelines, storage tanks and railcars may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance and are insured under the property, business interruption and liability policies of USD and certain of its subsidiaries, subject to the deductibles and limits under those policies, which we consider to be reasonable and prudent under the circumstances to cover our operations and assets. However, such insurance does not cover every potential risk associated with our assets, and we cannot ensure that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage, or that these levels of insurance will be available in the future at commercially reasonable prices. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows. As we grow, we will continue to monitor our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

AVAILABLE INFORMATION
We make available free of charge on or through our Internet website at www.usdpartners.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. We intend to post information for public disclosure, in accordance with Regulation FD, on our website. Information contained on our website is not part of this report.
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Item 1A. Risk Factors
You should carefully consider the risk factors below in connection with the other sections of this Annual Report. Realization of one or more of these risk factors could have an adverse effect on our business, operating results, cash flows and financial condition, as well as the value of an investment in our common units. These are not all the risks that could impact our business, operating results, cash flows and financial condition as there may be risks that are unknown to us or known immaterial risks that become material over time or when compounded with unpredictable events.
Risks Related to our Business and Industry
The COVID-19 pandemic has adversely affected our ability to grow our business, and the ultimate effect on our operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.
The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there have been significant reductions in demand for, and fluctuations in the prices of, crude oil, natural gas and natural gas liquids. If the reduced demand for crude oil continues for a further prolonged period, particularly if the global oversupply of crude oil also continues, our operations, financial condition and cash flows may be materially and adversely affected in the future.
Our operations also may be adversely affected if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, or other restrictions in connection with the pandemic. We have already implemented workplace restrictions, including guidance for when our employees may work remotely if able, in our offices and work sites for health and safety reasons and are continuing to monitor national, state and local government directives where we have operations and/or offices. Furthermore, the collapse in the demand for oil caused by this unprecedented global health and economic crisis has had, and is reasonably likely to continue to have, contributed to significantly depressed crude oil prices throughout much of last year, which has negatively impacted our customers and thereby has limited our ability to grow our business.
Given the current challenges in our industry and world economic conditions, there is an increased chance that counterparties to our contracts do not perform their obligations, either as a result of an inability to pay or a claim that they are not required to pay (whether under a force majeure provision or otherwise). Such claims and interruptions in payment may have an adverse impact on our expected revenue under the applicable contract or cause us to incur additional expenses associated with a challenge to such nonpayment or claim, which revenue or expenses may be material.
The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the duration and scope of the COVID-19 pandemic, including the impact of coronavirus mutations and additional resurgences; further actions by businesses and governments in response to the pandemic; and the speed and effectiveness of responses to combat the virus including the development, availability and public acceptance of effective treatments or vaccines. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify in this Annual Report. COVID-19 may also materially adversely affect our operating and financial results in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.
We depend on a limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.
We generate the vast majority of our operating cash flow in connection with providing terminalling services at our crude oil terminals. Substantially all of the capacity at our crude oil terminals is contracted under multi-year, take-or-pay terminal services agreements. A continued sustained reduction in the prices of crude oil and other
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commodities could have a material adverse effect on our customers’ businesses. In particular, oil sands production in Canada is particularly susceptible to decline as a result of long-term reductions in the price of crude oil due to its relatively high production costs. As a result, some of our customers may have material financial or liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger or better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders. In addition, liquidity issues resulting from sustained lower crude oil prices could lead our customers to go into bankruptcy or could encourage them to seek to repudiate, cancel, renegotiate or fail to renew their agreements with us for various reasons. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively limited number of customers for a substantial portion of our revenue.
Additionally, the sole contract at our West Colton terminal is terminable at any time upon 150 days’ notice. If we were unable to renew our contract with one or more of these customers, including customers at our Hardisty, Stroud or Casper terminals, on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all.
Our contracts are subject to potential commitment reductions or termination at various times, which creates renewal risks.
We provide terminalling services for liquid hydrocarbons and biofuels under contracts with terms of various durations and renewal. Of the six terminal services agreements with customers of our Hardisty terminal, one agreement will expire at the end of June 2022, two agreements will expire at the end of June 2023, and two agreements could expire at the end of 2024 unless USD’s DRU project described in the next paragraph has successfully been completed. Approximately two-thirds of the volume commitments under the remaining contract will expire in June 2022, with the remainder expiring in June 2024 unless USD’s DRU project has successfully been completed by such date. Our sole customer contract for our West Colton terminal is terminable at any time by either party on 150 days’ notice. Of the three terminal services agreements with our Casper terminal customers, one agreement expires in August 2021, one agreement expires in December 2021 and one agreement expires in December 2022. Approximately two-thirds of the volume commitments under our sole third-party customer contract for our Stroud terminal will expire in June 2022, with the remainder expiring in June 2024. However, the portion of this contract expiring in 2024 is subject to early termination in the event that USD’s DRU project has successfully been completed.
Furthermore, as discussed under Item 1. Business—Business Segments—Sponsor Initiatives at Hardisty—USD’s Diluent Recovery Unit Project, with its patented diluent recovery unit “DRU” technology, USD is pursing long-term solutions to transport heavier grades of crude oil produced in Western Canada. As described in the prior paragraph, expirations and renewals for some of our contracts at the Hardisty terminal and the Stroud terminal will depend on whether USD’s DRU project is successfully completed. The completion of the DRU project is subject to risk associated with construction projects, including USD having sufficient financing, permits and approvals, and the actions of third party construction personnel. USD is under no obligation to us to complete the DRU conversion or compensate us for lost revenue under our contracts related to the status of the DRU project.
As these contracts expire, we will have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio if, for example, prevailing crude oil prices and the associated spreads between different grades of crude oil remain at levels, or decline below levels, where transportation of crude oil by rail is economic. Depending on prevailing market conditions at the time of a contract renewal, customers with fee-based contracts may desire to enter into contracts under different fee or term arrangements or may seek to purchase such capacity on an uncommitted basis. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, or replace lost revenue upon changes in contract terms (including those in connection with the DRU project), our revenue and cash flows could decline and both our ability to make cash distributions to our unitholders and our
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ability to remain in compliance with the covenants under our credit facility could be materially and adversely affected.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.
We generate the vast majority of our operating cash flow in connection with providing terminalling services at our crude oil terminals, all of which receive the majority of their crude oil from the Canadian oil sands through the Hardisty hub. Due to the lack of diversification in our assets and geographic location, an adverse development in our businesses or areas of operations, especially to our crude oil terminals, including those due to catastrophic events, worldwide health events including the recent coronavirus outbreak, weather, regulatory action or decreases in the price of, or demand for, crude oil, could have a significantly greater impact on our results of operations and distributable cash flow to our common unitholders than if we maintained more diverse assets and locations. In particular, due in part to relatively high production costs, oil sands production in Canada may be particularly susceptible to decline as a result of long-term declines in the price of crude oil and was negatively impacted by the depressed pricing environment due to the effects of the COVID-19 pandemic, which has impacted and could in the future further impact our ability to secure additional long-term customer contracts and renewals at our Hardisty terminal and our Casper terminal, and the ability of USD Group LLC to contract for and complete expansions. In addition, events that impact the supply of crude oil in Western Canada, such as extreme weather, forest fires, and facility downtime, and events that increase the take-away capacity, such as the construction of new pipelines would have a similar impact.
We may not be able to compete effectively and our business is subject to the risk of a capacity overbuild of midstream infrastructure and the entrance of new competitors in the areas where we operate.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively. Our terminals compete with existing and potential new hydrocarbon by rail terminals, as well as alternative modes of transporting hydrocarbons from production centers to refining or aggregation centers, such as existing and potential new crude oil pipelines and water-borne vessels. Our competitors include other midstream companies, major integrated energy companies, independent producers and refiners, as well as commodity marketers and traders of widely varying sizes, financial resources and experience. We compete on the basis of many factors, including geographic proximity to production areas, market access, rates, terms of service, connection costs and other factors. Many of our competitors have access to capital resources significantly greater than ours.
A significant driver of competition in some of the markets where we operate is the risk of development of new midstream infrastructure capacity driven by the combination of (i) significant increases in oil and gas production and development in the particular production areas, both actual and anticipated, (ii) low barriers to entry and (iii) generally widespread access to relatively low cost capital. This environment exposes us to the risk that these areas become overbuilt, resulting in an excess of midstream infrastructure capacity. We face these risks in particular with respect to the potential development of additional pipeline takeaway capacity from the Canadian oil sands region, where our customers source the majority of the crude oil handled at our terminals. Most midstream projects require several years of “lead time” to develop and companies like us that develop such projects are exposed (to varying degrees depending on the contractual arrangements that underpin specific projects) to the risk that expectations for oil and gas development in the particular area may not be realized or that too much capacity is developed relative to the demand for services that ultimately materializes. If we experience a significant capacity overbuild in one or more of the areas where we operate, it could have a material adverse effect on our business, financial condition, results of operations, and as a result, our ability to make distributions to our unitholders.
Adverse developments affecting the fossil fuel industry or drilling activity, including continuing low or further reduced prices of crude oil or biofuels, reduced demand for crude oil products and increased regulation of drilling, production or transportation could cause a reduction of volumes transported through our terminals.
Our business, including our ability to grow our business through the contracting and development of new terminals, as well as our ability to secure renewals or extensions of agreements with customers at our existing terminals, depends on the continued development, production and demand for crude oil and other liquid
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hydrocarbons from our existing markets, as well as other areas unserved or underserved by existing alternative transportation solutions. The willingness of exploration and production companies to develop and produce crude oil in particular producing regions in Canada and the United States depends largely on their ability to conduct these activities profitably, which in turn depends largely upon the markets for and prices of crude oil and other commodities. A continued sustained reduction in the prices of crude oil and other commodities would have a material adverse effect on our business. For example, our business was negatively impacted by the depressed commodity pricing environment resulting from the effects of the COVID-19 pandemic. The factors impacting the prices of crude oil and other commodities include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions, and other factors, including:
worldwide and regional economic conditions;
worldwide and regional political events, including actions taken by foreign oil producing nations;
worldwide and regional weather events and conditions, including natural disasters and seasonal changes that could decrease supply or demand;
worldwide health events including the recent coronavirus outbreak;
the levels of domestic and international production and consumer demand;
the availability of transportation systems with adequate capacity;
fluctuations in demand for crude oil, such as those caused by refinery downtime or turnarounds;
fluctuations in the price of crude oil, which may have an impact on the spot prices for the transportation of crude oil by pipeline or railcar;
increased government regulation or prohibition of the transportation of hydrocarbons by rail;
the volatility and uncertainty of world crude oil prices as well as regional pricing differentials;
fluctuations in gasoline consumption;
the price and availability of alternative fuels;
changes in mandates to blend renewable fuels, such as ethanol, into petroleum fuels;
the price and availability of the raw materials used to produce ethanol, such as corn;
the effect of energy conservation measures, such as more efficient fuel economy standards for automobiles;
the nature and extent of governmental regulation and taxation, including the amount of subsidies for ethanol and other alternative sources of energy;
fluctuations in demand from electric power generators and industrial customers;
expected political or regulatory changes that could restrict development or production of crude oil and other, liquid hydrocarbons;
a decline in investor sentiment regarding the oil and gas industry;
restrictions on access to development capital by oil and gas companies; and
the anticipated future prices of oil and other commodities.
The prices of crude oil and related products remain volatile and subject to the influence of many global factors, such as the Organization of the Petroleum Exporting Countries, or OPEC, policy, the balance of supply versus demand for those products in various markets and geopolitical risks. Our terminals primarily transport crude oil produced from the Canadian oil sands, which are considered to have relatively high production costs. Exploration and production companies operating in the Canadian oil sands have reduced, and may further reduce, capital spending for expansion projects designed to increase crude oil production. Declines in crude oil prices for a prolonged period of time have resulted in and may in the future result in further reductions in capital spending, which could decrease the likelihood that our existing customers would renew their contracts with us at current prices
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or at all, reduce the opportunities for us to grow our assets and otherwise have a material adverse impact on our business and results of operations.
The dangers inherent in our operations could cause disruptions and expose us to potentially significant losses, costs or liabilities and reduce our liquidity. We are particularly vulnerable to disruptions in our operations because most of our terminalling operations are concentrated at the Hardisty, Stroud and Casper terminals.
Our operations are subject to significant hazards and risks inherent in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline or railcar ruptures and spills, third-party interference and mechanical failure of equipment at our terminals, any of which could result in disruptions, pollution, personal injury or wrongful death claims and other damage to our properties and the property of others. There is also risk of mechanical failure and equipment shutdowns both in the normal course of operations and following unforeseen events. Because the vast majority of our cash flow is generated from operations conducted at our crude oil terminals, any sustained disruption at any of these terminals, the Gibson storage terminal, which is the source of all of the crude oil handled by our Hardisty terminal, the Express pipeline, which is the primary source of the crude oil handled by the Casper terminal, or the Cushing hub and pipelines feeding into or out of the Cushing hub, which is the destination of the crude oil handled by the Stroud terminal, would have a material adverse effect on our business, financial condition, results of operations and cash flows and, as a result, our ability to make distributions to our unitholders.
Any reduction in our or our customers’ ability to utilize third-party storage facilities, pipelines, railroads or trucks that interconnect with our terminals or to continue utilizing them at current costs could negatively impact customer volumes and renewal rates at our terminals.
We and the customers of our terminals are dependent upon access to third-party storage facilities, pipelines, railroads and truck fleets to receive and deliver crude oil and other liquid hydrocarbons to or from us. The continuing operation of such third-party storage facilities, pipelines, railroads and other midstream facilities or assets is not within our control. Any interruptions or reduction in the capabilities of these third parties due to testing, line repair, reduced operating pressures, or other causes in the case of pipelines, or track repairs, derailments or other causes, in the case of railroads, could result in reduced volumes transported through our terminals.
We entered into a facilities connection agreement with Gibson whereby Gibson constructed a pipeline to provide our Hardisty terminal with exclusive pipeline access to Gibson’s Hardisty storage terminal, which is the source of all of the crude oil handled by our Hardisty terminal. In addition, substantially all of the crude oil handled by our Casper terminal has historically been sourced from the Express pipeline. Our customer base is accordingly constrained by customer access to Gibson’s Hardisty storage terminal in the case of our Hardisty terminal, and the Express pipeline in the case of our Casper terminal. If our existing customers don’t maintain their capacity with Gibson or Express, or in the case of our Casper terminal, our customers’ capacity allocations on the Express pipeline are reduced by prorations due to the capacity demands of other shippers or other reasons, the volume shipped by our existing customers may be reduced or our customers may choose not to renew their agreements with us at existing rates and volumes, if at all, which would have a material adverse effect on our results of operations and ability to make quarterly distributions to our unitholders.
Similar issues could arise based on other capacity issues arising before or after a customer’s products reach or leave our terminals, including rail capacity constraints and constraints at receiving terminals or other midstream facilities downstream of receiving terminals. For example, in the past, increase in demand for utilization of our Hardisty terminal has been limited by the ability of the railroads to increase staffing to meet this demand. If the railroads are unwilling or unable to meet the existing and potential future demand for our terminals, our ability to retain customers or grow our terminal would be materially impacted.
We do not own some of the land on which our terminals are located, which could disrupt our operations.
We do not own all of the land on which our West Colton terminal is located, which land we obtained the right to use through leases from the Class I railroad servicing this terminal. Our ability to provide comprehensive services
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to our customers on the leased land depends in large part on our ability to maintain and extend these leases, which are currently cancellable at will by either party. We are therefore subject to the possibility of lease cancellation, more onerous terms and/or increased costs to retain the land necessary to operate this terminal. Our loss of these rights, through our inability to renew or the unwillingness of the land owner to negotiate right-of-way contracts or leases, or otherwise, could cause us to cease operations on the affected land, incur costs to dismantle and remove existing facilities, increase costs related to continuing operations elsewhere and reduce our revenue.
The fees charged to customers under our agreements with them for the transportation of crude oil may not escalate sufficiently or at all to cover increases in costs, and the agreements may be temporarily suspended or terminated in some circumstances, which would affect our profitability.
We generate the vast majority of our operating cash flow in connection with providing terminalling services at our crude oil terminals. A substantial amount of the capacity at our crude oil terminals is contracted under multi-year, take-or-pay terminal services agreements, which, in the case of our Hardisty and Stroud terminals, are subject to inflation-based rate escalators. Some of the terminal services agreements at our Casper terminal are not subject to inflation-based rate escalators. Any inflation-based escalators in our terminal services agreements may be insufficient to compensate for increases in our costs. Additionally, some customers’ obligations under their agreements with us may be temporarily suspended upon the occurrence of certain events, some of which are beyond our control, or may be terminated in the case of uninterrupted force majeure events of over one year wherein the supply of crude oil is curtailed or cut off. Force majeure events may include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, pandemics (including potentially the COVID-19 pandemic), explosions, mechanical or physical failures of our equipment or facilities of our customers, or any cause or causes of any kind or character (except financial) reasonably beyond the control of the party failing to perform. If either the escalation of fees under the terminal services agreements at our terminals is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability and ability to make quarterly distributions to our unitholders could be materially and adversely affected.
Exposure to currency exchange rate fluctuations will result in fluctuations in our cash flows and operating results.
Currency exchange rate fluctuations could have an adverse effect on our results of operations. A substantial portion of the cash flows from our current assets will be generated in Canadian dollars, but we intend to make distributions to our unitholders in U.S. dollars. As such, a portion of our distributable cash flow will be subject to currency exchange rate fluctuations between U.S. dollars and Canadian dollars. For example, if the Canadian dollar weakens significantly, the corresponding distributable cash flow in U.S. dollars could be less than what is necessary to pay our minimum quarterly distribution.
A significant strengthening of the U.S. dollar relative to other currencies could result in an increase in our financing expenses and could materially affect our financial results under generally accepted accounting policies, or GAAP. In addition, because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. In addition, under GAAP, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable and capital lease obligations are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant non-monetary foreign currency exchange gains and losses in certain periods.
Increases in rail freight costs may adversely affect our results of operations.
The largest component of a shipment of crude by rail is the rail freight transportation costs. Unlike terminal services fees, which are typically established by multi-year contracts, railroad freight transportation has traditionally been purchased on a spot basis. Recently the railroads servicing some of our terminals have begun to seek multi-year term agreements, which also increase costs to our customers to the extent not utilized. High spot rail freight costs from or to our terminals, or high term rates or long contract terms, may make the shipment of crude or other liquid hydrocarbons less attractive or unattractive to our customers and potential customers. In addition, transporters
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of hydrocarbons by rail compete with other parties, such as coal, grain and corn, which ship their product by rail. Demand for transportation of crude or other products by rail is currently and has previously caused shortages in available locomotives and railroad crews. Such shortages may ultimately increase the cost to transport hydrocarbons by rail. Additionally, diesel fuel costs generally fluctuate with increasing and decreasing world crude oil prices, and accordingly are subject to political, economic and market factors that are outside of our control. Diesel fuel prices are a significant component of the costs to our customers of shipping hydrocarbons by rail. Increased costs to ship hydrocarbons by rail could curtail demand for shipment of hydrocarbons by rail which would have an adverse effect on our results of operations and cash flows and our ability to attract new customers and retain existing customers.
We may be subject to liability or expense in connection with the use of our railcars by our customers.
We lease an aggregate of 1,432 railcars from various railcar manufacturers and financial entities and we provide these railcars to our customers, including an affiliate of USD, pursuant to master fleet services agreements. Although our customers are generally responsible for the use, maintenance and condition of the railcars subject to their master fleet services agreements with us, we, and not our customers, are directly responsible to our lessors. In the event that our lessors seek to recover any costs at lease expiration resulting from the condition of the railcars, they will primarily look to us to recoup these amounts. Although our customers have generally agreed to be responsible for any costs we incur as a result of their use of our railcars, our customers may deny culpability for any specific costs. In the event that we are unable to resolve disputes related to return costs with our lessors and our customers, we may be obligated to pay the associated costs ourselves or the disputes may result in legal proceedings. Any such legal proceedings may be costly and we may not be able to recover our costs of participation in such proceedings from either the lessors or our customers. In addition, in the event that any such legal proceeding results in a judgment against us that is not reimbursable by our customer, such judgment could result in material costs for us. Finally, as the lessee of our railcars, we may be named in any legal proceedings related to any damage to third parties or the environment caused by the use of our railcars by our customers. In the event that we are unable to obtain indemnification from our customers as a result of such potential claims, we may incur material costs and liabilities. Any costs or liabilities resulting from our customers’ use of our railcars could have a material adverse effect on our business, financial condition, results of operations and cash flows and, as a result, our ability to make distributions.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, or if we fail to recover anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the provision of terminalling services, including:
damage to railroads and terminals, related equipment and surrounding properties caused by natural disasters, acts of terrorism and actions by third parties;
damage from construction, vehicles, farm and utility equipment or other causes;
leaks of crude oil and other hydrocarbons or regulated substances or losses of oil as a result of the malfunction of equipment or facilities or operator error;
blockades of rail lines or other interruptions in service due to actions of third parties;
ruptures, fires and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These and similar risks could result in substantial costs due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could also have a material adverse effect on our operations. We are not fully insured against all risks
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inherent in our business. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in claims for remediation, damages to natural resources or injuries to personal property or human health. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates, particularly following a significant accident or event for which we seek insurance. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.
Risks Related to our Ability to Grow through Acquisitions or Development of New Assets
If we are unable to make acquisitions on economically acceptable terms from USD or third parties, our future growth would be limited, and any acquisitions we may make could reduce, rather than increase, our cash flows and ability to make distributions to unitholders.
A portion of our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in cash flow. If we are unable to make acquisitions from USD or third parties, because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase agreements, we are unable to obtain financing for these acquisitions on economically acceptable terms, we are outbid by competitors or we or the seller are unable to obtain any necessary consents, our future growth and ability to increase distributions to unitholders will be limited. Energy Capital Partners must also approve the acquisition of the securities of any entity by us if the acquisition exceeds specified thresholds. Furthermore, even if we do consummate acquisitions that we believe will be accretive, we may not realize the intended benefits, and the acquisition may in fact result in a decrease in cash flow. Any acquisition, including the integration of any such acquisition, involves potential risks, including, among other things:
mistaken assumptions about revenues and costs, including synergies;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the overall costs of equity or debt;
the diversion of management’s attention from other business concerns;
unforeseen difficulties operating in new product areas or new geographic areas; and
customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our right of first offer to acquire certain of USD’s existing assets and projects and certain projects that it may develop, construct or acquire in the future is limited and subject to risks and uncertainty, and ultimately we may not acquire any of those assets or businesses.
The Omnibus Agreement provides us with a right of first offer on certain of USD’s existing assets and projects as well as any additional midstream infrastructure that it may develop, construct or acquire, subject to certain exceptions. This right expires on October 15, 2021. The consummation and timing of any future acquisitions pursuant to this right will depend upon, among other things, USD’s continued development of midstream infrastructure projects and successful execution of such projects, USD’s willingness to offer assets for sale and obtain any necessary consents, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions or successfully integrate assets acquired pursuant to our right of first offer. Furthermore, USD is under no obligation to accept any offer that we may choose to make. Additionally, the approval of Energy Capital Partners is required for the sale of any assets by USD or its
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subsidiaries, including us (other than sales in the ordinary course of business), acquisitions of securities of other entities that exceed specified materiality thresholds and any material unbudgeted expenditures or deviations from our approved budgets. Energy Capital Partners may make these decisions free of any duty to us and our unitholders. This approval would be required for the potential acquisition by us of any of USD’s projects, as well as any other projects or assets that USD may develop or acquire in the future or any third-party acquisition we may intend to pursue jointly or independently from USD. Energy Capital Partners is under no obligation to approve any such transaction. Please refer to the discussion under Item 10. Directors, Executive Officers and Corporate Governance— Special Approval Rights of Energy Capital Partners regarding the rights of Energy Capital Partners. In addition, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. Further, our right of first offer may be terminated by USD at any time in the event that it no longer controls our general partner. Please refer to the discussion under Part II, Item 8. Financial Statements and Supplementary Data, Note 13. Transactions with Related Parties for additional information regarding the Omnibus Agreement.
Growing our business by constructing new assets subjects us to construction risks and risks that supplies for such facilities will not be available upon completion thereof.
One of the ways we intend to grow our business is through the construction of new assets. The construction of new assets requires the expenditure of capital, some of which may exceed our resources, and involve regulatory, environmental, political and legal uncertainties. If we undertake the construction of new assets, we may not be able to complete them on schedule or at all or at the budgeted cost. Actions by third parties that we do not control may cause delay in construction, which could result in lost revenue or contract termination rights relating to the new asset. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new significant asset, the construction will occur over a period of time, and we will not receive any revenues until after completion of the project, if at all. Moreover, we may construct assets to provide services to capture revenue which does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of potential demand for our services in our decision to construct new assets, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating demand for our services. As a result, new assets we construct may not be able to attract sufficient demand to achieve our expected investment return, which could materially and adversely affect our results of operations, cash flows and financial condition.
We intend to distribute a significant portion of our available cash, which could limit our ability to pursue growth projects and make acquisitions.
Pursuant to our cash distribution policy we intend to distribute most of our available cash, as that term is defined in our partnership agreement, to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute most of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our senior secured credit agreement on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.
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Risks Related to our Ability to Make Cash Distributions
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including reimbursements to our general partner, to enable us to pay distributions to holders of our common and general partner units.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
our entitlement to minimum monthly payments associated with our take-or-pay terminal services agreements and the impact of credits for unutilized contractual capacity;
our ability to acquire new customers and retain existing customers;
the rates and terminalling fees we charge for the volumes we handle;
the volume of crude oil and other liquid hydrocarbons we handle;
damage to terminals, railroads, pipelines, facilities, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third-party pipelines, railroads or facilities upon which our customers rely for transportation services;
leaks or accidental releases of products or other materials into the environment, including explosions, chemical fumes or other similar events, whether as a result of human error, natural disaster or otherwise;
prevailing economic and market conditions; including low or volatile commodity prices and their effect on our customers;
our desired levels of liquidity and reduction of debt;
the effects of worldwide health events, including the recent coronavirus outbreak;
the level of our operating, maintenance and general and administrative costs;
regulatory action affecting railcar design or the transportation of crude oil by rail;
delays or increased costs caused by blockades or other interruptions in rail services; and
the supply of, or demand for, crude oil and other liquid hydrocarbons.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
the level and timing of capital expenditures we make;
the cost of acquisitions, if any;
our debt service requirements and other liabilities;
our requirements to pay distribution equivalents on Phantom Units pursuant to the terms of the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan, or A/R LTIP;
fluctuations in our working capital needs;
fluctuations in the values of foreign currencies in relation to the U.S. dollar, including the Canadian dollar;
our ability to borrow funds and access capital markets;
restrictions contained in our debt agreements;
the amount of cash reserves established by our general partner; and
other business risks affecting our cash levels.
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The amount of cash we have available for distribution to holders of our common units and general partner units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not be able to make cash distributions during periods when we record net earnings for financial accounting purposes.
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion and our partnership agreement does not require us to pay any distributions at all. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners must approve any distributions made by us.
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.2875 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion. Beginning in the first quarter of fiscal 2020, the board of directors of our general partner reduced the quarterly dividend to $0.111 per unit, or $0.444 per unit on an annualized basis, 70% below the distribution with respect to the fourth quarter of 2019. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, if any, must approve any distributions made by us. Our partnership agreement does not require us to pay distributions at all and our general partner’s board of directors has broad discretion in setting the amount of cash reserves each quarter. Investors are cautioned not to place undue reliance on the permanence of our cash distribution policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make and the decision to make any distribution is determined by the board of directors of our general partner as well as the members of our general partner’s board of directors appointed by Energy Capital Partners, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor or its affiliates to the detriment of our common unitholders.
Our general partner’s discretion in establishing cash reserves may reduce the amount of distributable cash flow to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of distributable cash flow to unitholders.
Risks Related to our Indebtedness and Ability to Raise Additional Capital
Restrictions in our senior secured credit agreement could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations under our senior secured credit agreement and to allow us to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our senior secured credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. Our senior secured credit agreement limits our ability to, among other things:
incur or guarantee additional debt;
make distributions on or redeem or repurchase units;
make certain investments and acquisitions;
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incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with other affiliates;
transfer, sell or otherwise dispose of assets;
engage in a materially different line of business;
enter into certain burdensome agreements; and
prepay other indebtedness.
Our senior secured credit agreement also includes covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. In addition, if we are unable to maintain our existing revenues and cash flows, particularly in connection with the potential renewal or extension of our existing take or pay agreements, we may be required to reduce our indebtedness or fall out of compliance with one or more of these ratios or tests.
The provisions of our senior secured credit agreement may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our senior secured credit agreement could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable along with triggering the exercise of other remedies. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations, including our Revolving Credit Facility.
Regulators and law enforcement agencies in the United Kingdom and elsewhere are conducting civil and criminal investigations into whether the banks that contributed to the British Bankers’ Association (the “BBA”) in connection with the calculation of daily London Interbank Offered Rate, or LIBOR, may have been under-reporting or otherwise manipulating or attempting to manipulate LIBOR. A number of BBA member banks have entered into settlements with their regulators and law enforcement agencies with respect to this alleged manipulation of LIBOR. Actions by the BBA or any other administrator of LIBOR, regulators or law enforcement agencies may result in changes to the manner in which LIBOR is determined, the phasing out of LIBOR or the establishment of alternative reference rates. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. As a result, LIBOR may be discontinued after 2021. Furthermore, in the United States, efforts to identify a set of alternative U.S. dollar reference interest rates that could replace LIBOR include proposals by the Alternative Reference Rates Committee of the Federal Reserve Board and the Federal Reserve Bank of New York. At this time, it is not possible to predict whether any such changes will occur, whether LIBOR will be phased out or any such alternative reference rates or other reforms to LIBOR will be enacted in the United Kingdom, the United States or elsewhere or the effect that any such changes, phase out, alternative reference rates or other reforms, if they occur, would have on the amount of interest paid on, or the market value of, our current or future debt obligations, including our Revolving Credit Facility. Uncertainty as to the nature of such potential changes, phase out, alternative reference rates or other reforms may materially adversely affect the trading market for LIBOR-based securities, including the terms of our Revolving Credit Facility and any interest rate swaps or other derivative agreements to which we are a party. Reform of, or the replacement or phasing out of, LIBOR and proposed regulation of LIBOR and other “benchmarks” may materially adversely affect the market value of, the applicable interest rate on and the amount of interest paid on our current or future debt obligations, including our Revolving Credit Facility. In addition, even if we have entered into interest rate swaps or other derivative instruments for purposes of managing our interest rate exposure, our strategies may not be effective
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as a result of the replacement or phasing out of LIBOR and other “benchmarks,” and we may incur substantial losses as a result.
Our ability to grow requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
We regularly consider and evaluate potential acquisitions and other opportunities to grow our business. Any limitations on our access to new capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, including our then current unit price, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.
Weak economic conditions, more stringent lending standards, higher interest rates and volatility in the financial markets have increased, and could in the future increase, the cost of raising money in the debt and equity capital markets, while diminishing the availability of funds from those markets. These factors among others may limit our ability to execute our growth strategy.
In September 2014, when Energy Capital Partners made a significant investment in USD, it indicated an intention to invest over an additional $1.0 billion of equity capital in USD, subject to market and other conditions. However, to date Energy Capital Partners has not provided any direct or indirect financial assistance to us. Furthermore, Energy Capital Partners must approve any issuances of additional equity by us, and its determination may be made free of any duty to us or our unitholders, and members of our general partner’s board of directors appointed by Energy Capital Partners must approve the incurrence by us or refinancing of our indebtedness outside of the ordinary course of business, which may limit our flexibility to obtain financing and to pursue other business opportunities.
Our existing debt and any additional debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
As of December 31, 2020, we had $197.0 million of outstanding borrowings under our senior secured credit agreement. We have the ability to incur additional debt, including up to $500 million under our existing senior secured credit agreement. Our level of indebtedness could have important consequences for us, including the following:
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes, may be impaired, or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and cash distributions to unitholders may be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt depends upon, among other things, our financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to take any of these actions on satisfactory terms or at all.
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We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our senior secured credit agreement prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our unitholders’ proportionate ownership interest in us will decrease;
the amount of distributable cash flow on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
Legal and Regulatory Risks Inherent in Our Business
Some of our customers’ operations cross the U.S./Canada border and are subject to cross-border regulation.
Our customers’ cross border activities subject them to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the Short Supply Controls of the Export Administration Act, the U.S.-Mexico-Canada Agreement) and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties on our customers. Our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially and adversely affected should our customers fail to comply with these cross-border regulations.
Changes in the provincial royalty rates and drilling incentive programs in Canada could decrease the oil and gas exploration and production activities in Canada, which could adversely affect the demand for our terminalling services.
Certain provincial governments collect royalties on the production from lands owned by the government of Canada. These fiscal royalty regimes are reviewed and adjusted from time to time by the respective provincial governments for appropriateness and competitiveness. Any increase in the royalty rates assessed by, or any decrease in the drilling incentive programs offered by, a provincial government could negatively affect the drilling activity, which could adversely affect the demand for our terminalling services.
Government regulation of oil production could have an adverse effect on our throughput volumes and distributable cash flow.
On December 3, 2018, the Alberta Government announced a temporary 8.7% cut (or a decrease of 325,000 barrels per day) in the production of raw crude oil and bitumen at facilities subject to its jurisdiction, starting on January 1, 2019. In late August 2019, the Alberta Government extended the curtailment end date to December 31, 2020, with possible earlier termination. During 2019, however, the Alberta Government increased the allowed production levels. For example, in late October 2019, the Alberta Government announced a special production allowance, whereby effective November 8, 2019, new wells drilled for conventional oil are exempt and, beginning with the December 2019 production month, producers were allowed to apply to produce above their curtailment order, as long as this extra production is shipped out of Alberta through additional rail capacity. In late October 2020, the Alberta Government announced that while the government will extend its regulatory authority to curtail oil production through December 2021, it will not set production limits as of December 2020. The Alberta Government has stated that it will closely monitor production, inventories, pipeline capacity and rail shipments and the Alberta Government could put production limits back in place, particularly if forecasts show storage inventories approaching maximum capacity, which production limits could negatively impact our business. This and similar future actual or anticipated governmental restrictions on the production of crude oil in the producing regions served
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by our terminals may cause our customers to reduce their production activities and delay or cancel new projects, which could in turn reduce the demand for our terminalling services. Except to the extent of our take-or-pay type arrangements, reductions in demand for our terminalling services resulting from governmentally imposed production cuts could reduce our cash flows and results of operations, and limit our ability to execute new terminalling services contracts, or extend existing terminalling services contracts.
Our business could be adversely affected if service on the railroads is interrupted or if more stringent regulations are adopted regarding railcar design or the transportation of crude oil by rail.
We do not own or operate the railroads on which crude oil carrying railcars are transported; however, we do manage a railcar fleet that is subject to regulations governing railcar design and manufacture. The volume of crude oil and liquid hydrocarbons transported in North America by rail has increased substantially in recent years. High-profile accidents involving crude oil carrying trains in recent years, in conjunction with increased use of rail transportation, have raised concerns about the environmental and safety risks associated with crude oil transport by rail and railcar design.
The DOT and Transport Canada released a series of directives and other actions to address rail safety concerns. Among the directives is a final rule requiring that CPC-1232 railcars used to transport crude oil and ethanol that are not compliant with required safety standards be phased out or retrofitted beginning April 1, 2020, with none in use after May 1, 2025. We currently provide railcar services for 1,432 railcars, 374 of which will still be under contract and require retrofitting pursuant to this directive. However, our customers have informed us that they intend to use these 374 railcars for transporting diesel fuel, as opposed to crude oil which would require retrofitting. While we do not foresee that these railcars will require retrofitting over the life of our lease or that these leases may expire before the regulatory deadline, certain of our lease agreements may permit for early retrofit of the railcars and will require retrofitting in the event that our customer decides to use these railcars to transport crude oil. We do not own any of the railcars in our railcar fleet and are not directly responsible for costs associated with the retrofitting of CPC-1232 railcars. However, costs associated with the retrofitting of railcars would increase the incremental monthly cost of the applicable railcar lease, which cost we may not always be able to pass through to our customers and could affect demand for our services. The timing of retrofits to the railcars we manage could disrupt our operations particularly if we are unable to work with our railcar suppliers on modification scheduling that avoids major disruptions.
Certain of the railroads serving our terminals have in the past and are currently considering imposing tariffs, fees or other limitations on the utilization of older railcar designs. These tariffs, fees and limitations could have the effect of imposing limits on the use of railcars that are more stringent than current regulatory standards, and could reduce the size of the overall railcar fleet available to be loaded at our terminals and increase the costs of obtaining usable railcars. Similar to other industry participants, compliance with existing and any additional environmental laws and regulations, or the imposition of additional tariffs, fees or limitations on the transportation of crude oil in certain railcars or all railcars by the railroads, could increase our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities, or the costs of our customers, which may reduce the attractiveness of rail transportation and limit our ability to extend existing agreements or attract new customers. Our master fleet services agreements generally obligate our customers to pay for modifications and other required repairs to our leased and managed railcar fleet. However, we cannot assure that we will be able to successfully pass all such regulatory costs on to our customers.
DOT and Transport Canada have also required operators to take certain precautions relating to rail routing, and mandated reductions in train speed and the implementation of new braking technology, to address rail safety concerns. The recent changes to U.S. and Canadian regulations and the adoption of additional federal, state, provincial or local laws or regulations, including any additional voluntary measures by the rail industry regarding railcar design or crude oil and liquid hydrocarbon rail transport activities, or efforts by local communities to restrict or limit rail traffic involving crude oil, could affect our business by increasing compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows. Moreover, any disruptions in the operations of railroads, including those due to shortages of railcars or qualified personnel, weather-related problems, flooding, drought, accidents, worldwide health events including the recent coronavirus
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outbreak, mechanical difficulties, strikes, lockouts or bottlenecks, could adversely impact our customers’ ability to move their products and, as a result, could affect our business.
Changes in, or challenges to, our pipeline rates and other terms and conditions of service could have a material adverse effect on our financial condition and results of operations.
Our dedicated crude oil pipelines, CCR Pipeline and SCT Pipeline, are subject to regulation by various federal, state and local agencies. FERC regulates the interstate transportation services provided on these pipelines under the ICA, the EPAct 1992 and the rules and regulations promulgated under those laws. FERC regulations require that rates for interstate service on pipelines that transport crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids be just and reasonable, not be unduly discriminatory and not confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. Under the ICA, FERC or interested persons may challenge existing or changed rates or services. FERC is authorized to investigate such changes and may suspend the effectiveness of a new rate upon its filing for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period during which the challenged rate was in effect. FERC may also order a pipeline to change its rates, and may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.
Intrastate transportation services provided by CCR Pipeline, the crude oil pipelines serving our Casper Terminal, are subject to regulation by the Wyoming Public Service Commission. The Wyoming Public Service Commission uses a complaint-based system of regulation, both as to matters involving rates and priority of access. In response to a complaint, the Wyoming Public Service Commission could limit our ability to increase our rates or to set rates based on our costs or order us to reduce our rates and require the payment of refunds to shippers. If we were to provide intrastate transportation services through our SCT Pipeline, the crude oil pipeline serving our Stroud terminal, we could elect to file a tariff covering such services with the Oklahoma Corporation Commission, which does not require such filings and does not regulate intrastate crude oil pipeline rates but does make filed pipeline tariffs available for public viewing.
FERC and state regulatory commissions generally have not investigated petroleum pipeline rates unless the rates are the subject of a shipper protest or a complaint. However, FERC or the Wyoming Public Service Commission could investigate our rates on their own initiative or at the urging of a third party. If FERC or the Wyoming Public Service Commission were to direct us to lower our tariff rates or decline to permit any proposed rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our CCR Pipeline and terminal located in Casper, Wyoming, or of our SCT Pipeline and terminal located in Stroud, Oklahoma, could suffer. In addition, if we were permitted to raise our tariff rates for services provided through the CCR Pipeline or SCT Pipeline but the rate increase was suspended for the maximum statutory period, there might be a significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could adversely affect our cash flow. Furthermore, competition from other pipelines and terminals may prevent us from raising our tariff rates even if FERC or the Wyoming Public Service Commission permits us to do so.
FERC and the Wyoming Public Service Commission periodically implement new rules, regulations and policies that can have a bearing on petroleum pipeline rates and terms and conditions of service. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.
We operate in a highly regulated industry and increased costs of compliance with, or liability for violation of, existing or future laws, regulations and other requirements could significantly increase our costs of doing business, thereby adversely affecting our profitability.
Our industry is subject to laws, regulations and other requirements including, but not limited to, those relating to the environment, safety, working conditions, public accessibility and other requirements. These laws and regulations are enforced by federal agencies including, but not limited to, the EPA, the DOT, PHMSA, the FERC,
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the FRA, the Federal Motor Carrier Safety Administration, or FMCSA, OSHA, state agencies such as the Texas Commission on Environmental Quality, the Railroad Commission of Texas, the California Environmental Protection Agency, or Cal/EPA, the California Public Utilities Commission, or CPUC, and Canadian agencies such as Environment Canada and Transport Canada as well as numerous other state and federal agencies. Ongoing compliance with, or a violation of, these laws, regulations and other requirements could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.
In addition, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, including in connection with the change in United States federal administration in January 2021, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. For example, See Item 1. Business—Impact of RegulationsClimate Change for information about certain actions the Biden Administration has taken targeting greenhouse gas emissions. Violation of environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions and construction bans or delays.
Under various federal, state, provincial and local environmental requirements, as the owner or operator of terminals, we may be liable for the costs of removal or remediation of contamination at our existing locations, whether we knew of, or were responsible for, the presence of such contamination. The failure to timely report and properly remediate contamination may subject us to liability to third parties and may adversely affect our ability to sell or rent our property or to borrow money using our property as collateral. Additionally, we may be liable for the costs of remediating third-party sites where hazardous substances from our operations have been transported for treatment or disposal, regardless of whether we own or operate that site. In the future, we may incur substantial expenditures for investigation or remediation of contamination that has not yet been discovered at our current or former locations or locations that we may acquire.
A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured or insurance is not otherwise available, subject us to substantial expense, including the cost to respond in compliance with applicable laws and regulations, fines and penalties, natural resource damages and claims made by employees, neighboring landowners and other third parties for personal injury and property damage. We may experience future catastrophic sudden or gradual releases into the environment from our pipeline or terminals or discover historical releases that were previously unidentified or not assessed. Although our inspection and testing programs are designed in compliance with applicable legal requirements to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business. Such discharges could also subject us to media and public scrutiny that could have a negative effect on the value of our common units.
Environmental, safety and other regulations are stringent. Penalties for violations have increased and may increase further in amount, and new environmental laws and regulations may be proposed and enacted. Moreover, interpretations of existing requirements change from time to time. While we cannot predict the impact that future environmental, health and safety requirements or changed interpretations of existing requirements may have on our operations, such future activity may result in material expenditures to ensure our continued compliance and material costs if we are found not to be in compliance. Such future activity could adversely affect our operations, cash flow and net revenues.
We are subject to stringent environmental and safety laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state, provincial and local environmental and safety laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from pipelines, railcars and terminals, and the imposition of substantial liabilities
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and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the EPA, the DOT, Environment Canada, Transport Canada and analogous state and provincial agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.
We may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under, or from our properties and terminals. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.
Also, some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on oil and gas production. States or localities could also elect to prohibit hydraulic fracturing altogether, as the State of New York announced in 2014, and the federal government could limit development, generally, on federal lands. While our operations are not directly affected by these actions, their impact on our oil and natural gas exploration and production customers could result in a decreased demand for the services that we provide.
We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.
Our operations require authorizations and permits that are subject to revocation, renewal or modification and can require operational changes to limit the effect or potential effect on the environment and/or health and safety. A violation of authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control and safety-related equipment. Any or all of these matters could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.
Legislation, regulatory initiatives, litigation and investor sentiment relating to climate change could result in increased operating costs, reduced demand for the services we provide and limits on our access to capital.
In response to studies suggesting that emissions of carbon dioxide, methane and certain other gases may be contributing to warming of the Earth’s atmosphere, over 190 countries, including the United States and Canada, reached an agreement to reduce GHG emissions at the Paris climate conference in December 2015. The terms of the Paris treaty to reduce GHG emissions are to become effective in 2020. In June 2017, President Trump announced that the United States intends to withdraw from the Paris treaty and to seek negotiations either to reenter the Paris treaty on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris treaty. In November 2019, the Trump administration formally moved to exit the Paris Agreement and officially exited the agreement in November 2020. However, in January 2021, President Biden signed an executive order to have the United States rejoin the agreement, and the United States formally rejoined the agreement in February 2021.
In addition, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs. Comprehensive climate legislation appears unlikely to be passed by either house of Congress in the near future,
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although additional energy legislation and other initiatives may be proposed that address GHGs and related issues. In addition, almost half of the states (including California and Texas, in which we operate), either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller sources could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations, and to the extent federal or state measures are successful in reaching hydrocarbon fuel usage, they could have an indirect effect on our business.
Independent of Congress, the EPA has adopted regulations to address GHG emissions under its existing CAA authority. For example, in 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, in September 2009, the EPA issued a final rule requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States. In November 2010, EPA expanded this existing GHG emissions reporting rule to petroleum facilities, requiring reporting of GHG emissions by regulated petroleum facilities to the EPA beginning in 2012 and annually thereafter. In October 2015, EPA further expanded its GHG emissions reporting program to include onshore petroleum and natural gas gathering and boosting activities, as well as natural gas transmission pipelines. We monitor and report our facilities’ GHG emissions. However, operational or regulatory changes or stakeholder demands could require additional monitoring and reporting at some or all of our other facilities at a future date. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the CAA. In October 2015, the EPA finalized the Clean Power Plan, or CPP, which imposes additional obligations on the power generation sector to reduce GHG emissions and which generally promoted a reduction in the demand for fossil fuels. Subsequently, the EPA repealed the CPP and replaced it with the Affordable Clean Energy rule, or ACE, which designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the EPA’s repeal and replacement of the CPP this decision may be subject to appeal.
Although it is not possible at this time to predict exactly how potential future laws or regulations addressing GHG emissions or oil and gas development in Canada or the United States would impact our business, any future federal, state or provincial laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs, could adversely affect demand for the crude oil and other liquid hydrocarbons we handle in connection with our services, and could adversely affect demand for our services by restricting or prohibiting our customers from conducting oil and gas production in certain areas. Moreover, the change in a regulation landscape means we may incur additional expenses that would not be applicable in a steady set of regulations. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our terminals, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations. In addition, there have been increasing efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private
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entities against oil and natural gas companies. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors.
The implementation of derivatives regulations could have an adverse effect on our ability to use derivatives contracts to reduce the effect of foreign exchange, interest rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Although the U.S. Commodity Futures Trading Commission and the other relevant regulators have finalized most of the regulations under the Dodd-Frank Act, they continue to review and refine initial rulemakings through additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivatives contracts, materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivatives contracts. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition, our results of operations and our cash flows.
Risks Inherent in Our Master Limited Partnership Ownership Structure
The credit and risk profile of our general partner and its owner, USD Group LLC, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital and additionally have a direct impact on our ability to pay our minimum quarterly distribution.
The credit and business risk profiles of our general partner and USD Group LLC, neither of which has a rating from any credit agency, may be factors considered in credit evaluations of us. This is because our general partner, which is owned by USD Group LLC, controls our business activities, including our cash distribution policy and growth strategy. In addition, a wholly-owned affiliate of our general partner is a customer of ours at our Hardisty terminal and Stroud terminal and may become a customer at other terminals we own or control in the future. Any adverse change in the financial condition of USD Group LLC, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, if any, may adversely affect our credit ratings and risk profile. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or USD Group LLC, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of USD Group LLC and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.
Our general partner and its affiliates, including USD, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.
USD indirectly owns a 42.3% limited partner interest and indirectly owns and controls our general partner, which owns a 1.7% general partner interest in us. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, USD. Conflicts of interest may arise between USD and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including USD, over the interests of our common unitholders. These conflicts include, among others, the following situations:
neither our Second Amended and Restated Agreement of Limited Partnership of USD Partners LP, or our partnership agreement, nor any other agreement requires USD to pursue a business strategy that favors us,
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and the directors and officers of USD have a fiduciary duty to make these decisions in the best interests of the members of USD. USD may choose to shift the focus of its investment and growth to areas not served by our assets;
USD may be constrained by the terms of its debt instruments, if any, from taking actions, or refraining from taking actions, that may be in our best interests;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, and the amount of adjusted operating surplus generated in any given period;
our general partner will determine which costs incurred by it are reimbursable by us;
our general partner may cause us to borrow funds in order to permit the payment of cash distributions and to make incentive distributions;
our partnership agreement permits us to classify up to $18.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of the common units;
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
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Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please refer to the discussion under Item 13. Certain Relationships and Related Transactions, and Director Independence regarding conflicts of interests and fiduciary duties of our general partner.
Affiliates of our general partner, including USD, and Energy Capital Partners and its affiliates may compete with us, and none of Energy Capital Partners, our general partner or any of their respective affiliates have any obligation to present business opportunities to us.
Neither our partnership agreement nor the Omnibus Agreement prohibits USD or any other affiliates of our general partner or Energy Capital Partners or its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, USD and other affiliates of our general partner, and Energy Capital Partners and its affiliates may acquire, construct or dispose of additional midstream infrastructure in the future without any obligation to offer us the opportunity to purchase any of those assets. For example, USD Group LLC currently owns the right to construct and further develop the Hardisty terminal, which USD Group LLC expects to complete in a future period. If we are unable to acquire these facilities from USD Group LLC, these expansions may compete directly with our Hardisty terminal for future throughput volumes, which may impact our ability to enter into new terminal services agreements, including with our existing customers, following the termination of our existing agreements or the terms thereof and our ability to compete for future spot volumes. As a result, competition from USD and other affiliates of our general partner could materially adversely impact our results of operations and distributable cash flow to unitholders.
Energy Capital Partners has substantial influence over USD and our general partner, and its interests may differ from those of USD, us and our public unitholders.
Energy Capital Partners currently has the right to appoint three of seven members of USD’s board of directors and three of nine members of our general partner’s board of directors and may in the future have the right to appoint the majority of USD’s board of directors if it invests a specified amount in USD, or certain other conditions are met. For so long as Energy Capital Partners is able to appoint more than one member to USD’s board of directors, USD will not, and will not permit its subsidiaries, including us and our general partner, to take or agree to take certain actions without the affirmative vote of Energy Capital Partners, including, among others, any acquisitions or dispositions and any issuances of additional equity interests in us. Energy Capital Partners may make these decisions free of any duty to us and our unitholders. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, if any, must approve any distributions made by us, any incurrence of debt by us and the approval, modification or revocation of our budget. As a result, Energy Capital Partners is able to significantly influence the management and affairs of USD and our general partner, including the amount of distributions we make, if any, our policies and operations, the appointment of management, future issuances of securities, amendments to our organizational documents and the entering into of extraordinary transactions. The interests of Energy Capital Partners may not in all cases be aligned with the interests of our common unitholders and, in certain situations, they have no duty to us or our unitholders.
Energy Capital Partners may have an interest in pursuing acquisitions, divestitures and other transactions that, in its judgment, could enhance its equity investment, even though such transactions might involve risks to our common unitholders, or Energy Capital Partners may have an interest in not pursuing transactions that would otherwise benefit us. For example, Energy Capital Partners could influence us to make acquisitions, investments and capital expenditures that increase our indebtedness or to sell revenue-generating assets or to not make such acquisitions, investments or capital expenditures. In addition, Energy Capital Partners may have different tax considerations that could influence its position, including regarding whether and when to dispose of assets and
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whether and when to incur new or refinance existing indebtedness. In addition, the structuring of future transactions by our general partner may take into consideration these tax or other considerations even where no similar benefit would accrue to our common unitholders or us. Energy Capital Partners may make the decisions to approve any acquisition or disposition by us free of any duty to us and our unitholders.
Energy Capital Partners’ influence on USD and our general partner may have the effect of delaying, preventing or deterring a change of control of our company. Energy Capital Partners and its affiliates and affiliated funds are in the business of making investments in companies in the energy industry and may from time to time acquire and hold interests in businesses that compete directly or indirectly with us. USD’s limited liability company agreement provides that Energy Capital Partners shall not have any duty to refrain from engaging directly or indirectly in the same or similar business activities or lines of business as us or any of our subsidiaries, and that in the event that Energy Capital Partners acquires knowledge of a potential transaction or matter which may be a corporate opportunity for itself and us or any of our subsidiaries, neither we nor any of our subsidiaries shall, to the fullest extent permitted by law, have any expectancy in such corporate opportunity, and Energy Capital Partners shall not, to the fullest extent permitted by law, have any duty to communicate or offer such corporate opportunity to us or any of our subsidiaries and may pursue or acquire such corporate opportunity for itself or direct such corporate opportunity to another person. Energy Capital Partners and its affiliates may also pursue acquisition opportunities that are complementary to our business and, as a result, those acquisition opportunities may not be available to us. Please refer to the discussion under Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners regarding the rights of Energy Capital Partners.
Energy Capital Partners, upon giving written notice, shall have the right to compel USD to effect the total sale of Energy Capital Partners’ interests in USD, which we refer to as an ECP Exit. Such a sale could include an acquisition by the remaining owners of USD of Energy Capital Partners’ interests in USD or an initial public offering of USD. If the ECP Exit has not been completed within 180 days of the date USD receives notice of Energy Capital Partners’ desire to sell, Energy Capital Partners shall have the right to compel USD to effect a total sale of USD pursuant to an auction process on terms and conditions determined by, and in a process managed by, the members of USD’s board of directors that are appointed by Energy Capital Partners, provided that certain conditions in connection with the sale are met.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please refer to the discussion under Item 13. Certain Relationships and Related Transactions, and Director Independence regarding conflicts of interests and fiduciary duties of our general partner.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner of the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please refer to the discussion under Item 13. Certain Relationships and Related Transactions, and Director Independence regarding conflicts of interests and fiduciary duties of our general partner.
Our general partner has limited liability regarding our obligations.
Our general partner has limited liability under our contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.
In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body, and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to U.S. federal income taxation. If you are not a person who meets the requirements to be a citizenship eligible holder and a rate eligible holder, you run the risk of having your units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if you are not a person who meets the requirements to be a citizenship eligible holder, you will not be entitled to voting rights.
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Cost reimbursements, which are determined in our general partner’s sole discretion, and fees due to our general partner and its affiliates for services provided are substantial and reduce our distributable cash flow to you.
Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under the Omnibus Agreement, our general partner determines the amount of these expenses. Under the terms of the Omnibus Agreement we are required to reimburse USD for providing certain general and administrative services to us. Our general partner and its affiliates also may provide us other services for which we will be charged fees. Payments to our general partner and its affiliates are substantial and reduce the amount of distributable cash flow to unitholders. For the twelve months ending December 31, 2021, we estimate that these expenses will be approximately $3.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. For a description of the cost reimbursements to our general partner, please read the discussion under Part II, Item 8. Financial Statements and Supplementary Data, Note 13. Transactions with Related Parties regarding reimbursements to our general partner under the Omnibus Agreement.
Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or the board of directors of our general partner and have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which is indirectly owned by USD. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
The unitholders are unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. At December 31, 2020, our general partner and its affiliates own 42.3% of the limited partnership interests entitled to vote in this matter (excluding general partner units and without consideration of any common units held by our officers, directors, employees and certain other persons affiliated with us).
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party at any time without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of USD Group LLC to transfer its membership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.
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The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of USD selling or contributing additional midstream infrastructure assets and businesses to us, as USD would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
USD Group LLC may sell or transfer our units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
USD Group LLC held 11,557,090 common units at December 31, 2020. We have agreed to provide USD Group LLC with certain registration rights. USD Group LLC and its affiliates may sell, transfer or pledge as security all or some of the units held by them without any duty to us. Such sale of units in the public or private markets, or pledging or transfer of units, could have an adverse impact on the price of the common units. At December 31, 2020, a value of up to $10.0 million of these common units were pledged as collateral by USD Group LLC for their letter of credit facility.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The holder of our incentive distribution rights may elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%, in addition to distributions paid on its general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based
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on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled the general partner to a quarterly cash distribution equal to distributions to our general partner on the incentive distribution rights in the prior quarter. Our general partner will also be issued the number of general partner units necessary to maintain our general partner’s interest in us at the level that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.
The New York Stock Exchange, or NYSE, does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to shareholders of corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks Inherent in an Investment in Us
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, the IRS could disagree with the positions we take or a change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. Therefore, if we were treated as a corporation for U.S. federal income tax purposes,
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there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S.-taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, the distributable cash flow to our unitholders could be further reduced.
Some of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of distributable cash flow. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a taxing authority could result in additional tax being imposed on us, reducing the distributable cash flow to our unitholders. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the distributable cash flow. Although these taxes may be properly characterized as foreign income taxes, you may not be able to credit them against your liability for U.S. federal income taxes on your share of our earnings.
If we were subjected to a material amount of additional entity-level taxation by individual states, counties or cities, it would reduce our distributable cash flow to our unitholders.
Changes in current state, county or city law may subject us to additional entity-level taxation by individual states, counties or cities. Several states have subjected, or are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the distributable cash flow to you and the value of our common units could be negatively impacted. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships, companies with multinational operations or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, companies with multinational operations, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of Congress and the Department of Treasury have proposed and considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to the U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impair our ability to qualify as a publicly traded partnership in the future.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals
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will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law.
Because a unitholder is treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to the unitholder, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes, on the unitholder’s share of our taxable income even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, excluding the impact of the Coronavirus Aid, Relief, and Economic Security Act, or CARES Act, enacted in 2020, under the federal tax reform enacted in 2017, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs for any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash flow.
Some of our activities may not generate qualifying income, and we conduct these activities in a separate subsidiary that is treated as a corporation for U.S. federal income tax purposes. Corporate U.S. federal income tax paid by this subsidiary reduces our cash available for distribution.
In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under Section 7704 of the Internal Revenue Code. To ensure that 90% or more of our gross income in each tax year is qualifying income, we currently conduct a portion of our business, relating to railcar fleet services, in a separate subsidiary that is treated as a corporation for U.S. federal income tax purposes.
Such corporate subsidiary is subject to corporate-level federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%, and will also likely pay state (and possibly local) income tax at varying rates, on its taxable income. If the IRS were to successfully assert that such corporate subsidiary has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.
For tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practicable, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on a sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. Thus, selling unitholders may recognize both ordinary income and capital loss from the sale of their units if the amount realized on a sale of their units is less than their adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a selling unitholder sells their units, they may recognize ordinary income from our allocations of income and gain to them prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units, may incur a tax liability in excess of the amount of cash received from the sale.
Certain actions that we may take, such as issuing additional units, may increase the U.S. federal income tax liability of unitholders.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units. In addition, the U.S. federal income tax liability of a unitholder could be increased if we take advantage of debt reduction opportunities (e.g., debt exchanges, debt repurchases or modifications of existing debt), dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as (i) to repay indebtedness currently outstanding or (ii) to acquire property that is not eligible for depreciation or amortization for U.S. federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our existing assets.
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There are limits on the deductibility of losses that may adversely affect unitholders.
In the case of taxpayers subject to the passive loss rules (generally, individuals, closely-held corporations and regulated investment companies), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of the unitholder’s entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years, but not by losses from other passive activities, including losses from other publicly traded partnerships. Further, excluding the temporary impact of the CARES Act, in addition to the other limitations described above, non-corporate taxpayers may only deduct business losses up to the gross income or gain attributable to such trade or business plus $250,000 ($500,000 for unitholders filing jointly). Amounts that may not be deducted in a taxable year may be carried forward into the following taxable year. This limitation shall be applied after the passive loss limitations and, unless amended, applies only to taxable years beginning prior to December 31, 2025.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. If you are a tax-exempt entity, you should consult a tax advisor before investing in our common units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a non-U.S. person, you should consult a tax advisor before investing in our common units.
We may be required to deduct and withhold amounts from distributions to foreign unitholders related to withholding tax obligations arising from the sale or disposition of our units by foreign unitholders.
Upon the sale, exchange or other disposition of a unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. If the transferee fails to satisfy this withholding requirement, we will be required to deduct and withhold such amount (plus interest) from future distributions to the transferee. Because the “amount realized” would include a unitholder’s share of our nonrecourse liabilities, 10% of the amount realized could exceed the total cash purchase price for such disposed units. To accommodate uncertainty surrounding the application of these withholding rules, the U.S. Department of the Treasury and the IRS have currently suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our units, occurring before January 1, 2022. Final regulations promulgated in October of 2020 impose withholding on transfers of certain publicly traded partnership interests, including transfers of our units, occurring after January 1, 2022. For transfers of publicly traded partnership interests involving brokers acting as a “qualified intermediary” (as such term is defined in the final U.S. treasury regulations promulgated in October of 2020), the withholding obligation is generally imposed on the broker rather than the transferee. There are also a number of exceptions to the withholding obligation that may apply
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depending on the transferor’s particular tax and circumstances. If you are a non-U.S. person, you should consult a tax advisor before investing in our common units.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations promulgated under the Internal Revenue Code and referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. A successful IRS challenge could also affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of Treasury and the IRS have issued Treasury Regulations that permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge this method, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may be required to recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
We have adopted certain valuation methodologies in determining a unitholders allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. For example, our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders.
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A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, you may become subject to state, local and foreign taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to U.S. federal income taxes, our unitholders are likely subject to other taxes, including state, local and foreign taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders are likely required to file state, local and foreign income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in Alberta, Canada, California, Texas, Wyoming and Oklahoma. Some of these jurisdictions currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. Our unitholders bear responsibility for filing all federal, state, local and foreign tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
General Risks Inherent in an Investment in Us
The price of our common units may fluctuate significantly, and you could lose all or part of your investment.
The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
our quarterly distributions;
our quarterly or annual earnings or those of other companies in our industry;
announcements by us or our competitors of significant contracts or acquisitions;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
future sales of our common units; and
other factors described in these “Risk Factors.”
Because our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price, our distributable cash flow, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates may increase in the future. As a result, interest rates on our future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect our interest expense and distributable cash flow, the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
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We may recognize impairment on long-lived assets and intangible assets.
Periodically, we review our long-lived assets for impairment whenever economic events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. For example, we evaluated our Casper terminal asset group for impairment in the first quarter of 2020 due to the overall downturn in the crude market and the decline in the demand for petroleum products. Based on our assessment under certain assumptions underlying our cash flow projections, as discussed under Part II, Item 8. Financial Statements and Supplementary Data, Note 9. Goodwill and Intangible Assets, we determined that the carrying amount of our Casper Terminal reporting unit exceeded its fair value at March 31, 2020. Accordingly, we recognized an impairment loss of $33.6 million in our goodwill asset. We also review our amortizable intangible assets for indicators of impairment in accordance with applicable accounting standards. Significant negative industry or general economic trends, disruptions to our business and unexpected significant changes or planned changes in our use of the assets may result in impairments to our amortizable intangible assets and other long-lived assets. However, to the extent that the assumptions underlying the assessment do not materialize, or projection of future financial performance underlying our cash flow projection for the Casper terminal could yield undiscounted cash flows and a fair value that indicate our long-lived assets are impaired. Moreover, these assumptions may change over time in response to the effects of the COVID-19 pandemic and the state of the commodity markets, which are inherently uncertain and difficult to predict. Any reduction in or impairment of the value of intangible assets will result in a charge against earnings, which could have a material adverse impact on our reported results of operations and financial condition.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.
We are managed and operated by the board of directors and executive officers of our general partner. All of the personnel that conduct our business are employed by affiliates of our general partner, but we sometimes refer to these individuals as our employees. Our ability to operate our business and implement our strategies depends on our continued ability and the ability of affiliates of our general partner to attract and retain highly skilled management personnel. Competition for these persons is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We or affiliates of our general partner may not be able to attract and retain qualified personnel in the future, and the failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business. Neither we nor our general partner maintains key person life insurance policies for any of our senior management team.
Terrorist or cyber-attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.
Terrorist attacks and threats, cyber-attacks, escalation of military activity, acts of war or other civil unrest may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States, Canada or their respective allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States and Canada. The disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.
We rely on information technology in all aspects of our business. A cyber-attack involving our information systems and related infrastructure could negatively impact our operations in a variety of ways, including, but not limited to, the following:
data corruption, communication interruption, or other operational disruption during transporting crude oil;
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
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a cyber-attack on our automated and surveillance systems could cause a loss in crude oil and potential environmental hazards;
a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
a cyber-attack resulting in the loss, disruption or disclosure of, or damage or denial of access to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Additionally, we do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows. Furthermore, the growth of cyber-attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
We are subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with U.S. generally accepted accounting principles, or GAAP. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We may be unsuccessful in maintaining our internal controls, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to assess, the effectiveness of our internal controls over financial reporting.
Any failure to maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a material adverse effect on the trading price of our common units.
For as long as we are a smaller reporting company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. “Smaller reporting companies” are able to provide simplified executive compensation disclosures in their filings, and have certain other scaled disclosure obligations in their SEC filings, including, among other things, being required to provide only two years of audited financial statements in annual reports. The scaled disclosures we provide in our SEC filings due to our status as a “smaller reporting company” may make it harder for investors to analyze our results of operations and financial prospects. If some investors find our common units to be less attractive as a result of the scaled disclosures, there also may be a less active trading market for our common units and our trading price may be more volatile.

Item 1B. Unresolved Staff Comments

Not Applicable.

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Item 2. Properties
A description of our properties is included in Item 1. Business, which is incorporated herein by reference.
Our Hardisty Terminal is located on land we own. Our Casper Terminal is located on land we own, as well as land owned by others, but operated by us under leases with private land owners, public authorities, railways, or public utilities. Our West Colton Terminal is located on land owned by others and is operated by us under easements and rights-of-way, licenses, leases or permits that have been granted by private land owners, public authorities, railways or public utilities. Our Stroud Terminal is located on land we own, as well as land owned by others, but operated by us under licenses, rights-of-way or leases with private land owners, public authorities, railways, or public utilities.
We have satisfactory title and other rights to our real estate assets.
Obligations under our senior secured credit facility are secured by a first priority lien on our assets and those of our restricted subsidiaries (as such term is defined in our senior secured credit facility), other than certain excluded assets. Title to the real property necessary for us to operate our business may also be subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of lease or acquisition by us. However, we do not believe that any of these burdens would materially detract from the value of these properties or from our interest in these properties or would materially interfere with their use in the operation of our business.

Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our consolidated financial condition or results of operations. In addition, under the Omnibus Agreement, USD has agreed to indemnify us for certain liabilities attributable to the ownership or operation of the assets contributed by them to us.

Item 4. Mine Safety Disclosures
Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchase of Equity Securities
Our common units are listed and traded on the NYSE, under the ticker symbol “USDP”.
On February 24, 2021, the last reported sales price of our common units on the NYSE was $5.10 per common unit. On February 24, 2021, there were approximately 5,700 common unitholders, nine of which were registered common unitholders of record. An established public trading market does not exist for our general partner units. All of our general partner units are held by USD Partners GP LLC.
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The amount of distributions we pay under our cash distribution policy and the decision to make any distribution are determined by the board of directors of our general partner. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.
Given the uncertainty in the energy industry stemming from the COVID-19 pandemic, the board of directors of our general partner in April 2020 made the proactive decision to strengthen our financial position by reducing our quarterly distribution to $0.111 per unit ($0.444 per unit on an annualized basis) and redeploying cash flow to opportunistically pay down debt. The board of directors of our general partner maintained distributions at this level for the remainder of 2020. We expect that the board of directors of our general partner will revisit the amount of any distributions we make on a quarterly basis based on prevailing and anticipated conditions impacting our business.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Please see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Securities Authorized for Issuance Under Equity Compensation Plans for information regarding our equity compensation plans as of December 31, 2020.
UNREGISTERED SALES OF EQUITY SECURITIES
None.
ISSUER PURCHASES OF EQUITY SECURITIES
None.
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 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K. Unless the context otherwise requires, references in this discussion to USD Partners, USDP, the Partnership, we, our, us or like terms refer to USD Partners and the following subsidiaries, collectively: Casper Crude to Rail LLC, CCR Pipeline LLC, Stroud Crude Terminal LLC, SCT Pipeline LLC, San Antonio Rail Terminal LLC, USD Logistics Operations GP LLC, USD Logistics Operations LP, USD Rail LP, USD Rail Canada ULC, USD Rail International S.A.R.L., USD Terminals Canada ULC, USD Terminals International S.A.R.L. and West Colton Rail Terminal LLC. 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 Part I, Item 1A. Risk Factors included elsewhere in this report.
We denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
Overview and Recent Developments
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 and biofuels 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, along with its partner, Gibson, is also pursuing long-term solutions 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. Construction of the project has commenced and USD expects that the DRU will be placed into service late in the second quarter or early in the third quarter of 2021. USD has secured the necessary financing, obtained all material permits and entered into fixed-price construction contracts regarding the construction of the project. USD’s patented DRU technology separates the diluent that has been added to the raw bitumen in the production process
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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. In addition, USD is constructing a new destination terminal in Port Arthur, Texas for the DRUbit™ that will be transloaded at our Hardisty origination terminal. Please refer to Part 1. Item 1A. Risk Factors—Our contracts subject us to renewal risks for a discussion of certain risks associated with these projects.
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
The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement worldwide. As a result, there have been significant reductions in demand for, and fluctuations in the prices of, crude oil, natural gas and natural gas liquids. In addition, in March 2020, members of the Organization of the Petroleum Exporting Countries and other oil producing countries including Russia, or OPEC+, failed to agree on oil production levels, which led to a substantial decline in oil prices and an increasingly volatile market. In March and April 2020, domestic oil and natural gas producers announced dramatic reductions or curtailments of their development programs, as well as plans to shut-in production. In April 2020, even though OPEC+ announced that it had reached an agreement to cut production by 9.7 million barrels per day, or Mmbpd, oil prices did not meaningfully increase. As concerns about domestic oil storage capacity being fully subscribed in May 2020 grew, on April 20, 2020, WTI oil futures priced at historic lows.
These events negatively impacted our customers and thereby limited our ability to grow our business during 2020. For example, as a result of the overall downturn in the crude market and the decline in the demand for petroleum products, in March 2020, we tested the goodwill associated with our Casper terminal for impairment, which resulted in an impairment loss. Declining demand for petroleum products could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper terminal. Refer to Part II. Item 8. Financial Statements and Supplementary Data, Note 9. Goodwill and Intangible Assets of this Report for further discussion of the impairment loss at the Casper terminal.
While the severity of the government-imposed restrictions in different regions and changes to consumer behavior have continued to evolve during the course of the pandemic, some economies started to reopen in the latter half of 2020. However, certain jurisdictions that began re-opening have returned to restrictions in light of increased numbers of new COVID-19 cases and new strains of the virus. Beginning in December 2020, several COVID-19 vaccines have received approval and have begun to be made available around the world. The timing of when the vaccines will be available for a majority of the world population remains uncertain, as there are several logistical and supply challenge issues that will have to be addressed. As such, there still remains considerable uncertainty about the ultimate impact and duration of the pandemic and its effects on the global economy.
Despite these uncertainties, recent efforts to reopen the economy have continued to lead to marginal increases in the demand for crude oil and petroleum products. As a result, crude oil prices have fully recovered and stabilized at pre-pandemic levels, as compared to the lower price levels that were present at the end of the first quarter and
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during the second quarter of 2020. As a result, as of the beginning of July 2020, producers in Canada and the U.S. started to bring back the temporary shut-in production from the first quarter of 2020, with mostly all of this production coming back online in Canada towards the end of 2020. Additionally, OPEC+ agreed in July 2020 to taper oil production cuts, which scaled back production cuts from 9.7 Mmbpd to 7.7 Mmbpd between August 2020 and January 2021. In January 2021, OPEC+ announced that it would increase production by 500,000 bpd, which would adjust the production reduction from 7.7 Mmbpd to 7.2 Mmbpd. This is consistent with what OPEC+ previously announced for January 2021 production. We believe that if the increases in demand for oil and natural gas continue, production levels will continue to trend higher during 2021. If demand and prices increase, the need for crude by rail export capacity from our terminals is also expected to increase. 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 lower 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 contracts. However, if the pandemic continues for a further extended period of time 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 this Annual Report on Form 10-K for further discussion of certain risks relating to the COVID-19 pandemic.
Given the uncertainty in the energy industry, as a proactive measure to strengthen our financial position and redeploy certain free cash flow to de-lever, the board of directors of our general partner elected in the first quarter of 2020 to reduce the quarterly distribution per unit declared by 70% as compared to the distribution for the fourth quarter of 2019. As a result, during the second, third and fourth quarters of 2020, we made net repayments towards reducing the outstanding balance of our Revolving Credit Facility totaling $27 million. Refer to Liquidity and Capital Resources—Cash Requirement—Distributions for further discussion.
Impact of Current Market Events
The amount by which the West Texas Intermediate, or WTI, price of crude oil exceeds the WCS price of crude oil, referred to as the WCS to WTI spread, is a driver of activity at our Hardisty terminal. The WCS to WTI spread was between $8-$15 per barrel during the fourth quarter of 2020 and averaged approximately $14 during the month of December 2020, which was slightly wider than the previous narrower spread levels experienced earlier in 2020. This wider spread was a result of production in Canada trending upwards towards levels that existed prior to the COVID-19 pandemic as discussed above. Consistent with the increase in supply, the demand for additional export capacity by customers of our Hardisty terminal in turn increased and as a result we experienced an increase in the average daily throughput during the fourth quarter of 2020 as compared to lower levels that existed in the second and third quarters at the Hardisty terminal. Going forward, we expect producers will continue to increase crude oil supply. Future WCS to WTI spreads recently published by Bloomberg for 2022 through 2024 average approximately $15 per barrel and reach approximately $17 per barrel towards the end of 2024. Given the current market conditions, as stated above, and as pipeline uncertainty remains, supply is expected to continue to be higher than pipeline takeaway capacity and as a result, the WCS to WTI spread should continue to support the need for a crude by rail egress solution. As this occurs, crude by rail volumes from Western Canada to the United States are expected to further increase during 2021. 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. Based on this forecasted increase in spending by producers in Canada and the forecasted WCS to WTI spread levels, we expect that throughput volumes at our Hardisty terminal will continue to trend upwards throughout 2021, from the low levels that existed during the second and third quarters of 2020.
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Consistent with crude oil production in Canada trending towards levels that existed prior to the COVID-19 pandemic, in the fourth quarter of 2020, 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 22% and have continued to increase to approximately 53% in February 2021. Heavy Canadian crude oil supply levels have also increased due to winter pipeline specification changes, as required pipeline blending ratios are higher in the winter months. As such, apportionment is also expected to continue to increase due to this factor and as supply increases and lack of available pipeline takeaway capacity remains. Crude oil inventory levels increased by approximately 30% during the fourth quarter of 2020 as compared to levels at the end of the third quarter 2020, consistent with the increases in supply and apportionment levels previously discussed. Given the expectation of increases in supply and higher apportionment levels, we expect that inventory levels will continue to increase in the first quarter of 2021. 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. Additionally, the anticipated in-service date of Enbridge’s Line 3 Replacement project to upgrade and expand an existing pipeline delivering Western Canadian crude to U.S. markets has been delayed to the fourth quarter of 2021 and could face potential legal disputes. 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 Governor has demanded that the pipeline be shut down by May 12, 2021. The Governor has revoked a 1953 Michigan easement that allowed Line 5 to pass through the bottom of the Straits of Mackinac. As environmental, regulatory and political challenges to increase pipeline export capacity remain, crude by rail exports will remain a valuable egress solution.
When producers in Western Canada bring back production, in the event relative WCS to WTI differentials make it economic to export crude oil, we expect demand for and utilization of our rail terminals to increase. This continues to remain uncertain and difficult to predict. In the long-term, 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 below, 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.
Alberta Government Update
Over the course of 2019 and part of 2020, the Alberta Government imposed limits on production of crude oil and bitumen. These limits were originally applicable through 2020. However, in late October 2020, the Alberta Government announced that it will not set production limits as of December 2020, however it will extend its regulatory authority to curtail oil production through December 2021. The Alberta Government has stated that it will closely monitor production, inventories, pipeline capacity and rail shipments. The Alberta Government could put production limits back in place, particularly if forecasts show storage inventories approaching maximum capacity.

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Growth Opportunities for our Operations
We apply a disciplined approach to pursuing our growth strategy, which may include organic growth initiatives as well as acquisitions of energy-related logistics assets. Potential acquisitions may include assets developed by our sponsor or by third-party logistics providers. We believe these represent attractive opportunities to leverage our established and scalable network footprint to enhance and extend our currently-contracted cash flows.
USD is currently pursuing several development projects related to long-term solutions to transport heavier grades of crude oil produced in Western Canada, as well as projects related to the storage and the transportation of liquid hydrocarbons and biofuels. As the role of biofuels continues to expand in the clean energy transition, we and USD are committed to offering new capabilities and services across growing demand in clean fuels to include ethanol, renewable diesel and biodiesel. These development projects are expected to be supported by multi-year, take-or-pay agreements with strategic customers which would generate stable and predictable cash flows, as discussed in further detail below.
Opportunities Related to USD’s Diluent Recovery Unit Project
In December 2019, USD and Gibson jointly announced an agreement to construct and operate a diluent recovery unit, or DRU, near Hardisty, Alberta, Canada. A subsidiary of ConocoPhillips has contracted to process 50,000 barrels per day of inlet bitumen blend through the DRU to be shipped by Canadian Pacific Railway and Kansas City Southern Railway Company to the Port Arthur Terminal, or PAT, to be constructed by USD, on the U.S. Gulf Coast. Construction of the DRU and PAT have commenced and USD expects they will be placed into service late in the second quarter or early in the third quarter of 2021. USD and Gibson are currently in commercial discussions with other potential producer and refiner customers to secure additional long-term, take-or-pay agreements to support future expansions of capacity at the DRU.
USD’s patented DRU process is designed to separate the diluent that is added to raw bitumen in the production process in order to meet 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 U.S. DRUbit™ is a market access solution designed to 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 diluted bitumen crude oil that is transported by pipeline today.
Management believes that the successful completion of USD’s Hardisty DRU project will enhance the sustainability and quality of the Partnership’s cash flows by significantly increasing the average tenor of terminalling services agreements at our Hardisty Terminal. For example, upon successful completion of the Hardisty DRU project and construction of the Port Arthur destination terminal described below, the average remaining terms of our three terminalling services agreements with ConocoPhillips at the Hardisty Terminal will extend from less than 3 years to over 10 years (through mid-2031). We expect that future customers of the Hardisty DRU project will enter into similar long-term, more sustainable commitments for terminalling services at the Partnership’s Hardisty Terminal. USD’s interest in the Hardisty DRU project would also be available for possible acquisition by the Partnership, and would be subject to the Partnership’s right of first offer on USD’s assets pursuant to the Omnibus Agreement between USD and the Partnership, which extends through October 15, 2021.
As mentioned, USD is constructing a new destination terminal in Port Arthur, Texas for the DRUbit™ that will be transloaded at our Hardisty Terminal. USD’s Port Arthur Terminal, or PAT, will have the capability for rail unloading, barge dock loading and unloading, tank storage and blending and will be pipeline connected to Phillips 66’s Beaumont Terminal, providing customers access to a large network of refining and marine facilities. The facility will be set up to handle DRUbit™, Dilbit and a heavy Canadian conventional barrel and manage the blending of DRUbit™ into a marketable product for shippers. The marine and pipeline delivery options for blended products at the terminal will allow customers to enhance market flexibility and take advantage of cost advantaged delivery options. PAT will be served by the Kansas City Southern railroad and sits on exclusive rail infrastructure, providing seamless scheduling, operations, and communications resulting in ratable and reliable service. Within the
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233-acre terminal footprint, there is ample waterfront and upland acreage that allows PAT expansion capabilities to accommodate any foreseeable demand.
We believe the PAT project is well positioned in a market poised for growth. The Port Arthur market is home to over 1.6 million barrels of refining capacity per the EIA and a growing petrochemical market. With ExxonMobil’s 250,000 barrel per day refinery expansion expected to be in service in 2023, and Motiva’s acquisition of the Flint Hills ethane cracker dovetailing into planned downstream expansions into the petrochemical market, Port Arthur’s heavily utilized midstream infrastructure can expect liquid volumes to increase.
Within the Port Arthur market, PAT will be well positioned to take advantage of these opportunities and other organic growth projects. Pipeline connectivity to the hub of Port Arthur’s liquids business provides an advantage through reduced costs to deliver crude locally relative to a barge alternative and will extend the market reach for customers of PAT. Customers of PAT will be able to deliver barrels by pipeline and water into Louisiana markets when the terminal goes into service. It is expected that customers of PAT will also be able to deliver into Houston in the future, as a pipeline connection project is currently under construction and is expected to be placed into service by 2022. USD’s Port Arthur Terminal would also be available for possible acquisition by the Partnership, and would be subject to the Partnership’s right of first offer on USD’s assets pursuant to the Omnibus Agreement between USD and the Partnership, which extends through October 15, 2021.
The timing and commencement of the DRU and Port Arthur projects will impact the amount of volume commitments at the Stroud Terminal. Upon the commencement of the DRU and Port Arthur projects prior to June 30, 2022, we expect the customer to elect to reduce the volume commitments at the Stroud Terminal attributable to the Partnership (and move commitments to the DRU) by one-third of the current commitment through June 30, 2022, at which point the agreement will terminate and there will be no renewal period. We also expect the customer to elect to fully terminate the volume commitments attributable to USDM. If the DRU and Port Arthur projects have not commenced prior to June 30, 2022, on a net basis after giving effect to the USDM volumes that will be assigned to the Partnership, the volume commitments at the Stroud Terminal attributable to the Partnership will remain the same and extend through June 30, 2024. Approximately one-third of the volume commitments attributable to USDM will also extend through June 30, 2024 and the remaining volume commitments attributable to USDM will terminate on June 30, 2022. Management believes that the lower utilization at the Stroud Terminal as a result of successful completion of the DRU project will be short-term in nature and will allow the Partnership the opportunity to offer terminalling services to other customers in need of access to the numerous markets connected to the Cushing oil hub.
Other Opportunities Related to Our Crude Oil Terminal Network
Western Canadian crude oil production is projected to increase throughout the next decade, driven primarily by developments in Alberta’s oil sands region. Additionally, certain end users, including refineries across North America, have made substantial investments in recent years in order to efficiently process heavy grades of crude oil, such as those from Western Canada. Additions to pipeline takeaway capacity from Western Canada to key demand centers in the United States are not expected to keep pace with forecasted production growth. As such, demand for rail takeaway out of Western Canada is expected to increase over the next several years and potentially longer if currently planned timelines are not met. Our strategically-located crude oil terminal network, with established capacity and scalable design, is well-positioned to meet these growing takeaway needs.
Hardisty Terminal
We have renewed and extended 100% of the capacity at our Hardisty Terminal through mid-2022, with approximately 73% extended through mid-2023 with customers under multi-year take-or-pay agreements. As previously discussed, upon the successful commencement of USD’s DRU and Port Arthur projects discussed above, approximately 32% of the Hardisty Terminal’s capacity will be automatically extended through mid-2031. We remain focused on renewing and extending our Hardisty agreements that expire in mid-2022 and mid-2023 on a multi-year take-or-pay basis. Additionally, if USD and Gibson are successful in securing an additional customer at the DRU, the capacity associated with such commitment will likely be contracted for transloading at the Hardisty Terminal on a long-term basis.
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USDG, pursuant to its development rights at the Hardisty Terminal, completed the Hardisty South expansion (“Hardisty South”) in early 2019. The existing Hardisty Terminal, which is owned by us, has designed capacity for two unit trains per day, or approximately 150,000 barrels per day. Hardisty South, which is owned by USDG, added one and one-half unit trains per day, or approximately 112,500 barrels per day, of takeaway capacity to the terminal by modifying the existing loading rack and building additional infrastructure and trackage. We believe Hardisty South could present an attractive future acquisition opportunity for the Partnership pursuant to our existing right of first offer, should USDG propose to sell or transfer the asset before October 15, 2021.
Stroud Terminal
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. Our Stroud Terminal is the only rail facility connected to the Cushing storage hub, which provides for strategic and competitive advantages. The benchmark price in the domestic spot market for U.S. crude oil known as West Texas Intermediate, or WTI, is set at the Cushing hub. According to the EIA, the Cushing storage hub has approximately 76 million barrels of working storage capacity. There is also an expansive pipeline infrastructure that connects into and out of the Cushing hub. Because of the vast connectivity that Cushing offers, crude oil that is delivered into Cushing can then be delivered to either local refineries or it can be shipped to other markets such as the United States Gulf Coast, which is the largest refinery complex in the U.S. As such, 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.
Approximately 50% of the Stroud Terminal’s current capacity is contracted under a multi-year, take-or-pay terminal services agreement between the Partnership and ConocoPhillips.
USDM has contracted the other 50% of the Stroud Terminal’s current capacity pursuant to the Marketing Services Agreement, or MSA, that was established at the time of the acquisition of the Stroud Terminal. Per the MSA, we granted USDM the right to market the capacity at the Stroud Terminal in excess of the capacity of our initial customer in exchange for a nominal per barrel fee. If the DRU project is not completed by June 30, 2022, then, pursuant to the MSA, certain commitment volumes at the Stroud Terminal attributable to USDM will be assigned to the Partnership, as discussed above.
Our sponsor is also evaluating a potential expansion of the Stroud Terminal to meet incremental customer demand, which could include the unloading of both WCS or DRUbit™. If pursued and successful, these efforts could provide us with cash flows incremental to those provided by our currently-contracted capacity. Additionally, any such development project would be wholly-owned by USDG and would be subject to our existing right of first offer, should USDG propose to sell or transfer the asset.
Casper Terminal
Our Casper Terminal currently includes approximately 100,000 bpd of loading capacity and 900,000 barrels of tank storage capacity. The Casper Terminal receives inbound crude oil primarily through our dedicated direct pipeline connection from Enbridge’s Express pipeline, which is subsequently loaded onto unit or manifest trains.

The Casper Terminal executed an agreement with a multi-national, investment grade customer for an initial three-year term that commenced on September 1, 2018. The agreement contains take-or-pay terms for terminalling and storage services in connection with one storage tank, as well as fees associated with actual throughput volumes and other services. Pursuant to this agreement and to supplement 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, which was placed into service during December 2019. Upon the completion of the outbound pipeline in December 2019, the Partnership entered into a second terminalling services agreement that contains the same terms as the first agreement, but in connection with a separate storage tank with the customer. This second agreement expires in December 2022.

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In December 2019, an existing customer of our Casper Terminal extended its terminalling services agreement that was to expire December 31, 2019, for an additional two years. This agreement was subsequently transferred to a third party marketing company in 2020. The agreement contains take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services.
In July 2019, Enbridge announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of drag reducing agent, or DRA, and additional pump stations. In late July 2020, Enbridge announced that it had placed 25,000 bpd of the additional capacity on its Express pipeline into service and plans to place the additional 25,000 bpd into service during 2021, which was extended from the previously expected in-service date of sometime during the first half of 2020. We anticipate that some of the additional volumes resulting from the increased capacity on the Express pipeline could be delivered to our Casper Terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity.
Opportunities Related to Our Sponsor’s Texas Deepwater Development on U.S. Gulf Coast
In October 2015, our sponsor entered into a joint venture to develop a premier U.S. Gulf Coast logistics terminal on a 988-acre parcel of property on the Houston Ship Channel. Its strategic location is uniquely positioned to provide customers with flexible market access to key demand centers, both domestic and abroad. Preliminary master planning efforts suggest that the property footprint is capable of supporting up to twelve million barrels of storage capacity, multiple docks (including barge and deep water), inbound and outbound pipeline connectivity, and a rail terminal with capacity to unload multiple unit trains per day. The property is in proximity to substantially all major inbound and outbound pipelines and can be directly accessed by multiple Class 1 railroads.
In August 2019, our Sponsor’s Texas Deepwater development joint venture and Equilon Enterprises LLC d/b/a Shell Oil Products US, or SOPUS, completed a project to retrofit and refurbish the Deer Park Rail Terminal, or DPRT, on the Houston Ship Channel. The DPRT has the capability of loading up to 48 railcars per day, or approximately 33,000 barrels of refined products per day. The terminal is also capable of providing additional value-added services, including the ability of adding lubricity additives and red dye. The facility is equipped with two operational tanks with 50,000 barrels of total storage capacity, which will service the railcar loading rack at the terminal with direct pipeline connectivity to the Deer Park Refinery and the Colex Products Terminal. While the initial focus will be on loading diesel into railcars initially destined to Mexico and the Permian Basin, there may be a potential to further expand the DPRT by adding incremental storage capacity and rail loading capabilities to handle additional refined products.
According to the February 2021 short-term outlook published by the EIA, worldwide fuel consumption is estimated to have decreased by approximately 8.9 Mmbpd in 2020 compared to 2019 due to the COVID-19 pandemic and restrictions on economic activity. The EIA projects that worldwide fuel consumption will increase by 5.4 Mmbpd by 2021 compared to 2020, based on the expectation that global markets will start to recover. Recent industry developments highlight the Gulf Coast’s strategic importance within global energy markets and its ability to meet growing demand. Since the ban on exports of crude oil was lifted in 2015, exports of crude oil and petroleum products from PADD III on the Gulf Coast have increased from approximately 3.5 million bpd to approximately 7.1 million bpd in 2019, which represented approximately 84% of the total crude oil and petroleum products exported out of the U.S. during 2019. The EIA’s Annual Energy Outlook published in February 2021 in its base case forecasts that in the long-term the U.S. is expected to remain a net exporter of crude oil and petroleum products. The U.S. continues to be an integral part of global oil markets and a significant source of supply, despite uncertainty surrounding post-pandemic expectations for oil and natural gas demand. Our sponsor’s Texas Deepwater development will continue to pursue projects that position the terminal to take advantage of this macro trend, and participate heavily in export markets.
Our sponsor expects that these industry dynamics will contribute to growing demand for storage, staging, blending, export and other logistics services along the Gulf Coast, including at its Houston Ship Channel property. Accordingly, our sponsor is actively engaged in commercial negotiations with potential customers to provide export solutions for crude oil, refined products, petrochemicals and natural gas liquids. Any such development project would be wholly-owned by USD and its joint venture partner, and USD’s interest in the Texas Deepwater development joint venture would be subject to our existing right of first offer should USD propose to sell or transfer
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its ownership. If successfully commercialized and developed, and subsequently acquired by us, the Texas Deepwater development represents a meaningful opportunity to add complementary logistics assets that diversify our current network and have the potential to add additional high-quality take-or-pay agreements with terms beyond those related to our existing network.
Right of First Offer
In connection with our IPO, we entered into the Omnibus Agreement with USD and USDG, pursuant to which we were granted a right of first offer on any midstream infrastructure assets that they may develop, construct, or acquire for a period of seven years after the closing of our IPO, or until October 15, 2021. Additional information about the Omnibus Agreement and the right of first offer are included in Note 13. Transactions with Related Parties of our consolidated financial statements at Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
We cannot assure you that USD will be able to develop or construct, or that we or USD will be able to acquire, any additional midstream infrastructure projects. Among other things, the ability of USD to further develop the Hardisty Terminal and Stroud Terminal, or any other project, and our ability to acquire such projects, will depend upon USD’s and our ability to raise additional equity and debt financing. We are under no obligation to make any offer, and USD and USDG are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer. Additionally, the approval of Energy Capital Partners is required for the sale of any assets by USD or its subsidiaries, including us (other than sales in the ordinary course of business), acquisitions of securities of other entities that exceed specified materiality thresholds and any material unbudgeted expenditures or deviations from our approved budgets. Energy Capital Partners may make these decisions free of any duty to us and our unitholders. This approval would be required for the potential acquisition by us of any projects to expand the Hardisty Terminal and Stroud Terminal, as well as any other projects or assets that USD may develop or acquire in the future or any third-party acquisition we may pursue independently or jointly with USD. Energy Capital Partners is under no obligation to approve any such transaction. Please refer to the discussion under Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners regarding the rights of Energy Capital Partners. If we are unable to acquire any projects to expand the Hardisty Terminal and Stroud Terminal from USD, these expansion projects, once completed, may compete directly with our existing business for future throughput volumes, which may impact our ability to enter into new terminal services agreements, including with our existing customers, following the termination of our existing agreements, or the terms thereof, and our ability to compete for future spot volumes. Furthermore, cyclical changes in the demand for crude oil and other liquid hydrocarbons may cause USD, or us, to further re-evaluate any future expansion projects, including expansion of the Hardisty Terminal and Stroud Terminal.

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.
Hardisty Terminal Services Agreements.    We have terminal services agreements with four high-quality, primarily investment grade counterparties or their subsidiaries: Cenovus Energy, Gibson, Suncor Energy, and ConocoPhillips. Substantially all of the terminalling capacity at our Hardisty Terminal is contracted under multi-
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year, take-or-pay terminal services agreements subject to inflation-based escalators with a volume-weighted average remaining contract life of 2.5 years as of December 31, 2020. Assuming the successful completion of USD’s DRU project, as previously discussed, which will automatically extend approximately 32% of the Hardisty Terminal’s capacity through mid-2031, the volume-weighted average remaining contract life of our Hardisty Terminal increases to approximately 7.5 years as of December 31, 2020. All of our counterparties are obligated to pay a minimum monthly commitment fee for the capacity to load an allotted number of unit trains, representing a specified number of barrels per month. If a customer loads fewer unit trains than its allotted amount in any given month, that customer will receive a credit for up to12 months. This credit may be used to offset fees on throughput volumes in excess of the customer’s minimum monthly commitments in future periods to the extent capacity is available for the excess volume. We will receive a per-barrel fee on any volumes handled in excess of the customers’ allowed amount, to the extent the additional volume is not subject to the credit discussed above. If a force majeure event occurs, a customers obligation to pay us may be suspended, in which case the length of the contract term will be extended by the same duration as the force majeure event.
Stroud Terminal Services Agreements.    Concurrent with our acquisition of the Stroud Terminal, we entered into a multi-year, take-or-pay terminalling services agreement with ConocoPhillips for the use of approximately 50% of the available capacity at the Stroud Terminal. The term of the initial agreement concluded on June 30, 2020 and was extended through June 2024, which is subject to certain early termination rights depending on the commencement of our Sponsor’s DRU project, as previously discussed. Our customer is obligated to pay a minimum monthly commitment fee and can load an allotted number of barrels per month. If our customer loads fewer barrels than its allotted amount in any given month, the customer receives a credit for up to 12 months. This credit may be used to offset fees on throughput volumes in excess of our customer’s minimum monthly commitments in future periods to the extent capacity is available for the excess volume. We will receive a per-barrel fee on any volumes handled in excess of our customer’s allotted amount, to the extent the additional volume is not subject to the credit discussed above.
We also entered into the MSA with USDM, as discussed above, whereby we granted USDM the right to market the capacity at the Stroud Terminal in excess of the capacity of our initial customer in exchange for a nominal per barrel fee. Upon expiration of our contract with the initial Stroud customer in June 2020, the same marketing rights now apply to all throughput at the Stroud Terminal in excess of the throughput necessary for the Stroud Terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud customer during the 12 months prior to expiration.
    Casper Terminal Services Agreements.    Our Casper Terminal includes terminalling services agreements with a high quality, investment grade multi-national customer and with a marketer customer. The multi-year agreements with these customers contain take-or-pay terms for terminalling and storage services and variable fees associated with actual throughput volumes and other services.
Additionally, we may on occasion utilize our available storage and throughput capacity to support our customers’ spot activity through buy-sell agreements that generate cash flows in addition to those provided by our multi-year agreements, and have also entered into a short-term agreement to facilitate spot transactions on behalf of USDM. We are actively pursuing term agreements with these spot customers.
West Colton Terminal Services Agreements.    Our West Colton Terminal is supported by a terminal services agreement with a subsidiary of an investment grade company pursuant to which we are paid fixed fees per gallon of ethanol transloaded at the terminal. The West Colton Terminal services agreement has been in place since July 2009 and is terminable at any time by either party upon 150 days’ notice.
Fleet Services
We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on multi-year, take-or-pay terms under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of December 31, 2020, our railcar fleet consisted of 1,432 railcars, which we leased from various railcar manufacturers and financial entities, including 1,058 C&I railcars. We have assigned certain payment and performance obligations under the leases and master fleet
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service agreements for 1,232 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars. Substantially all of our current railcar fleet is dedicated to customers of our Hardisty Terminal. Our master fleet services agreements have a weighted-average remaining contract life of 1.5 years as of December 31, 2020. At the end of June 2020, leases on 250 railcars were assigned directly to our customers. Additionally, effective February 1, 2021, leases on 999 railcars were assigned directly to one of our customers. The agreements on an additional 233 railcars expired at the end of February 2021. We do not expect the assignments or expirations to have a material impact on our business, cash flows or results of operations.
Under the master fleet services agreements, we provide customers with railcar-specific fleet services, which may include, among other things, the provision of relevant administrative and billing services, the repairs 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 customers typically pay 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 II, Item 8. Financial Statements and Supplementary Data, Note 15. Segment Reporting.
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 flows 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:
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the amount of cash available for making distributions to our unitholders;
the excess cash flows 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 operating activities, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted EBITDA and DCF:
Year Ended December 31,
2020 2019 2018
(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities $ 45,814  $ 38,442  $ 45,129 
Add (deduct):
Amortization of deferred financing costs (829) (1,072) (866)
Deferred income taxes 973  (79) 3,971 
Changes in accounts receivable and other assets 3,052  2,895  (815)
Changes in accounts payable and accrued expenses 1,045  604  639 
Changes in deferred revenue and other liabilities (5,217) (6,066) 196 
Interest expense, net 8,895  11,936  11,356 
Provision for (benefit from) income taxes (41) 662  (2,669)
Foreign currency transaction loss (gain) (1)
267  365  (14)
Non-cash deferred amounts (2)
1,637  2,809  (205)
Adjusted EBITDA 55,596  50,496  56,722 
Add (deduct):
Cash paid for income taxes (3)
(324) (1,206) (814)
Cash paid for interest (8,593) (11,775) (10,038)
Maintenance capital expenditures (171) (216) (201)
Distributable cash flow
$ 46,508  $ 37,299  $ 45,669 
    
(1)    Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.
(2)    Represents the change in non-cash contract assets and liabilities associated with revenue recognized at blended rates based on tiered rate structures in certain of our customer contracts and deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.
(3)    Includes the net effect of tax refunds of $480 thousand received in the third quarter of 2020 associated with carrying back U.S. net operating losses incurred during 2020 and prior periods allowed for by the provisions of the CARES Act.
Operating Costs
Our operating costs are comprised primarily of subcontracted rail services, pipeline fees, repairs and maintenance expenses, materials and supplies, utility costs, insurance premiums and lease costs for facilities and equipment. In addition, our operating expenses include the cost of leasing railcars from third-party railcar suppliers and the shipping fees charged by railroads, which costs are generally passed through to our customers. We expect our expenses to remain relatively stable, but they may fluctuate from period to period depending on the mix of
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activities performed during a period and the timing of these expenditures. We expect to incur additional operating costs, including subcontracted rail services and pipeline fees, when we handle additional volumes at our terminals.
Our management seeks to maximize the profitability of our operations by effectively managing both our operating and maintenance expenses. As our terminal facilities and related equipment age, we expect to incur regular maintenance expenditures to maintain the operating capabilities of our facilities and equipment in compliance with sound business practices, our contractual relationships and regulatory requirements for operating these assets. We record these maintenance and other expenses associated with operating our assets in “Operating and maintenance” costs in our consolidated statements of operations.
Volumes
The amount of Terminalling services revenue we generate depends on minimum customer commitment fees and the throughput volume that we handle at our terminals in excess of those minimum commitments. These volumes are primarily affected by the supply of and demand for crude oil, refined products and biofuels in the markets served directly or indirectly by our assets. Additionally, these volumes are affected by the spreads between the benchmark prices for these products, which are influenced by, among other things, the available takeaway capacity in those markets. Although customers at our terminals have committed to minimum monthly fees under their terminal services agreements with us, which will generate the majority of our Terminalling services revenue, our results of operations will also be affected by:
our customers’ utilization of our terminals in excess of their minimum monthly volume commitments;
our ability to identify and execute accretive acquisitions and commercialize organic expansion projects to capture incremental volumes; and
our ability to renew contracts with existing customers, enter into contracts with new customers, increase customer commitments and throughput volumes at our terminals, and provide additional ancillary services at those terminals.

General Trends and Outlook

    In addition to the discussion provided below, refer also to the Market Update section included in Part II, Item 7. Management’s Discussion and Analysis, Overview and Recent Developments.
Hardisty and Stroud Terminals Customer Contract Renewals
During 2019, we successfully re-contracted the remaining available capacity of our Hardisty Terminal with multi-year take-or-pay agreements with investment grade customers. To date, we have renewed and extended 100% of the capacity at our Hardisty Terminal through mid-2022, with approximately 73% extended through mid-2023 with customers under multi-year take-or-pay agreements. Upon the successful completion of USD’s DRU project previously discussed, approximately 32% of the Hardisty Terminal’s capacity will be automatically extended through mid-2031. Certain of our terminalling services agreements at our Hardisty terminal that expire in mid-2023 include a tiered rate structure that includes rate decreases that occur annually on July 1st of each year throughout the term of the agreement. Additionally, due to the significantly longer contract tenor of the terminalling services agreements associated with the DRU volumes, contracted rates on an annual basis will be lower as compared to historical, shorter-term, agreements, but support a higher net present value to the Partnership and a more predictable cash flow profile. We remain focused on renewing, extending or replacing our agreements at Hardisty that expire in mid-2022 and mid-2023 with new, multi-year take or pay commitments, including, if USD and Gibson are successful in securing additional customers at the DRU, on a long-term basis similar to the existing DRU customer. In addition, we successfully re-contracted the capacity at our Stroud Terminal that was set to expire in June 2020 with a term that extends through June 2024. However, upon the successful completion of USD’s DRU project, our Stroud customer will have the right to terminate a portion of this agreement immediately and the remainder in June 2022, as previously discussed. Management believes that the lower utilization at the Stroud Terminal as a result of successful completion 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.
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Potential Impact of Hardisty and Stroud Deficiency Credit Usage by Our Customers
As previously discussed, customers of our Hardisty and Stroud terminals are obligated to pay a minimum monthly commitment fee for the capacity to load an allotted number of unit trains, representing a specified number of barrels per month. If a customer loads fewer unit trains than its allotted amount in any given month, that customer will receive a credit for up to 12 months, also referred to as a deficiency credit. This credit may be used to offset fees on throughput volumes in excess of the customer’s minimum monthly commitments in future periods to the extent capacity is available for the excess volume. As of late January 2021, based on current circumstances and conversations with our customers, we reasonably expect that customers of our Hardisty and Stroud terminals plan to use some of their accrued deficiency credits during 2021. As such, we will be required to defer the recognition of the revenue associated with the expected usage of the deficiency credits during 2021 until either the deficiency credit has been used or the likelihood of the credit’s usage has been deemed remote. Additionally, we could incur incremental costs associated with loading the additional trains for our customers if they do use their accrued deficiency credits, but such costs are not expected to be material.
Casper Terminal Customer Contract Renewals and Expirations
Our last legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. We continue to seek other opportunities to enhance the utilization and profitability of the Casper Terminal with other producers, refiners and marketers of crude oil. The revenue provided by the current agreements at our Casper Terminal, certain of which contain take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services, may be less predictable than the revenue historically provided by the legacy contracts, which were based on minimum volume commitments. We have not yet entered into arrangements to replace all of the revenue previously provided by the legacy contracts at the Casper Terminal.
In July 2019, Enbridge Inc. announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of DRA and pump stations. We anticipate that some of the additional volumes resulting from the increased capacity on the Express pipeline could be delivered to our Casper Terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity. Our ability to secure additional commercial opportunities and replace the revenue previously generated under the expired contracts may be limited until Enbridge successfully completes its DRA project. In late July 2020, Enbridge announced that it has placed 25,000 bpd of the additional capacity on its Express pipeline into service and plans to place the additional 25,000 bpd into service sometime in 2021. For a discussion of the risks associated with our ability to renew, extend or replace customer contracts, see Item 1A. Risk Factors—Our contracts subject us to renewal risks.
Factors That May Impact Future Results of Operations
Demand for Rail Transportation of Crude Oil and Biofuels
High-growth crude oil production areas in North America are often located at significant distances from refining centers, creating constantly evolving regional imbalances, which require the expedited development of flexible and sustainable transportation solutions. The extensive existing rail network, combined with rail transportation’s relatively low capital and fixed costs compared to other transportation alternatives, has strategically positioned rail as a long-term transportation solution for growing and evolving energy infrastructure needs. In the event that additional pipeline capacity is constructed, or crude oil production decreases significantly, demand for transportation of crude oil by rail may be adversely impacted. Please also refer to the Market Update section included in Part II Item 7. Management’s Discussion and Analysis, Overview and Recent Developments.
Changes in environmental and gasoline blending regulations may affect the use of ethanol in the market for transportation fuel. Due to corrosion concerns unique to biofuels, such as ethanol, the long-haul transportation of biofuels via multi-product pipelines is less efficient and less economical than rail. Rail also helps aggregate fragmented ethanol production across the country. In the event that dedicated pipelines are constructed, or additional technologies are developed to allow for more economical transportation of biofuels on multi-product pipelines, demand for transportation of biofuels by rail may be affected.
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Supply and Demand for Crude Oil and Refined Products
The volume of crude oil and biofuels that we handle at our terminals and the number of railcars for which we provide and perform railcar-specific fleet services ultimately depends on refining and blending margins. Refining and blending margins are dependent mostly upon the price of crude oil or other refinery feedstocks and the price of refined products. These prices are affected by numerous factors beyond our control, including the global supply and demand for crude oil and gasoline and other refined products. The supply of crude oil will depend on numerous factors, including commodity pricing, improvements in extractive technology, environmental regulation and other factors. We believe that our Adjusted EBITDA and DCF will not be affected in the near term due to our multi-year, take-or-pay terminal services agreements. However, our ability to grow through expansion or acquisitions and our ability to renew or extend our terminalling services agreements could be affected by a long-term reduction in supply or demand.
Customer Contracts
Our business is subject to the risk that we may not be able to renew, extend or replace our customer contracts as their terms expire. During 2019, we renewed and extended multiple terminalling services agreements at the Hardisty Terminal and Stroud Terminal with existing customers for terms that are generally improved from the original agreements. Additionally, although all legacy contracts at our Casper Terminal terminated, we have partially replaced these agreements with arrangements that we have negotiated with new customers. While the legacy contracts provided for minimum volume commitments, the new agreements provide for committed storage fees and variable fees associated with actual throughput volumes. With regards to the terminalling service agreement at our Stroud Terminal, our Stroud customer will have the right to terminate a portion of their agreement immediately and the remainder in June 2022, upon the successful completion of USD’s DRU project, as previously discussed. Management believes that the lower utilization at the Stroud Terminal as a result of successful completion 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. Refer to the discussion above under the heading General Trends and Outlook for information regarding customer contract renewals and expirations and changes in fee structures. For a discussion of the risks associated with our ability to renew, extend or replace customer contracts, see Item 1A. Risk Factors—Our contracts subject us to renewal risks.
Regulatory Environment
Our operations are subject to federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling of liquid hydrocarbons and biofuels. Additionally, we are subject to regulations governing railcar design and evolving regulations pertaining to the shipment of liquid hydrocarbons and biofuels by rail as discussed in greater detail in Item 1. Business—Impact of Regulation. Similar to other industry participants, compliance with existing environmental laws and regulations, as well as those that may be added in the future, could increase our overall cost of doing business. Such costs, include the costs we incur to construct, maintain, operate and upgrade equipment and facilities, or the costs of our customers, which may reduce the attractiveness of rail transportation. Our master fleet services agreements generally obligate our customers to pay for modifications and other required repairs to our leased and managed railcar fleet. However, we cannot assure that we will be able to successfully pass all such regulatory costs on to our customers. While changes in these laws and regulations could indirectly affect our results of operations, financial condition and cash flows, we believe that consumers of our services place additional value on utilizing established and reputable third-party providers to satisfy their rail terminalling and logistics needs, which may allow us to increase market share relative to customer-owned operations or smaller operators that lack an established track record of safety and regulatory compliance.
Acquisition Opportunities
We plan to continue to pursue strategic acquisitions of energy-related logistics assets from both USD and third parties that will provide attractive returns to our unitholders, including facilities that provide for storage and transportation of liquid hydrocarbons and biofuels. We intend to leverage our industry relationships and market
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knowledge to successfully execute on such opportunities, which we may pursue independently or jointly with USD. We have entered into the Omnibus Agreement with USD and USDG, pursuant to which USDG has granted us a right of first offer on any midstream infrastructure assets that they may develop, construct, or acquire until October 15, 2021, seven years after the closing of our IPO. Additional information regarding our growth opportunities is discussed in Growth Opportunities for our Operations and information regarding the Omnibus Agreement is presented in Note 13. Transactions with Related Parties—Omnibus Agreement of Item 8. Financial Statement and Supplementary Data. We cannot assure you that USD will be able to develop or construct, or that we or USD will be able to acquire, any other midstream infrastructure projects, including any projects to expand the Hardisty Terminal and Stroud Terminal. Among other things, the ability of USD to further develop the Hardisty Terminal and Stroud Terminal, or any other project, and our ability to acquire such projects, will depend upon USD’s and our ability to raise additional equity and debt financing. We are under no obligation to make any offer, and USD and USDG are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer. Additionally, the approval of Energy Capital Partners is required for the sale of any assets by USD or its subsidiaries, including us (other than sales in the ordinary course of business), acquisitions of securities of other entities that exceed specified materiality thresholds and any material unbudgeted expenditures or deviations from our approved budget. Energy Capital Partners may make these decisions free of any duty to us and our unitholders. This approval would be required for the potential acquisition by us of any projects to expand the Hardisty Terminal and Stroud Terminal, as well as any other projects or assets that USD may develop or acquire in the future or any third-party acquisition we may pursue independently or jointly with USD. Energy Capital Partners is under no obligation to approve any such transaction. Additional discussion of the special approval rights of Energy Capital Partners is included in Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners. If we are unable to acquire any projects to expand the Hardisty Terminal and Stroud Terminal from USD, which USD retained the right to develop and operate, these projects may compete directly with our current terminal assets for future throughput volumes. As a result, our ability to enter into new terminal services agreements, or to renew such agreements with our existing customers, following the termination of our existing agreements or the terms thereof and our ability to compete for future spot volumes could be affected. Furthermore, cyclical changes in the demand for crude oil and other liquid hydrocarbons may cause USD or us to reevaluate any future expansion projects, including any projects to expand the Hardisty Terminal and Stroud Terminal. Lastly, if we do not make acquisitions on economically beneficial terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our results of operations and cash flows.
Interest Rate Environment
The interest rates available in U.S. and international credit markets remain near historic lows. This could affect our future ability to access the credit markets to fund our future growth. Additionally, as with other yield-oriented securities, our unit price could be affected by the level of our cash distributions and the associated implied distribution yield. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and, as such, a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity. However, we expect that our cost of capital would remain competitive, as our competitors would face similar circumstances. We have entered into an interest rate swap contract to partially mitigate our exposure to interest rate fluctuations on our variable rate debt. The swap contract establishes a fixed LIBOR value for our debt of 0.84%. Refer to Note 18. Derivative Financial Instruments of Item 8. Financial Statement and Supplementary Data in this Report for more information on our interest rate swap.
Unit Based Compensation
We incur unit based compensation expenses associated with the Phantom Units granted to directors, officers and employees of our sponsor pursuant to the A/R LTIP. We recognize the expense associated with the outstanding Phantom Units ratably over its requisite service period. For more information related to our A/R LTIP including total compensation expense not yet recognized refer to Note 20. Unit Based Compensation of Item 8. Financial Statements and Supplementary Data of this Annual Report.

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Factors Affecting the Comparability of Our Financial Results
The comparability of our current financial results in relation to prior periods are affected by the factors described below.
Casper Terminal Customer Contract Expirations and Goodwill Impairment
Our last legacy terminalling services agreement at our Casper Terminal expired at the end of August 2019 and was not renewed or extended. The expired agreement contributed $9.3 million to our “Terminalling Services” revenue and $6.5 million of Adjusted EBITDA during the twelve months preceding the expiration of the agreement. Additionally, a legacy customer of our Casper Terminal, whose terminal services agreement with us expired in October 2018, extended until December 2018, and did not renew. The expired agreement contributed $7.3 million to our “Terminalling services” revenue and $5.6 million of Adjusted EBITDA during the twelve months preceding termination of the agreement. Also, one of our initial legacy terminalling services agreements expired in late August 2017. The expired agreement contributed $15.0 million to our “Terminalling services” revenue and $12.0 million of Adjusted EBITDA during the twelve months preceding expiration of the agreement. Furthermore, in March 2020, we tested the goodwill associated with our Casper Terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reductions of expected throughput levels and changes in expectations for current contracts in place at the Casper Terminal. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the year ended December 31, 2020.
Income Tax
In June 2019, the Canadian Province of Alberta enacted a tax rate decrease that reduced the tax rate on business income from the previous rate of 12% to an ultimate rate of 8% effective for 2022. The reduction in the tax rate on business income was to be phased in over three years beginning with a reduction to an 11% rate effective July 1, 2019, with further reductions of 1% in each successive year until it reached 8% on January 1, 2022. In December 2020, the Alberta government passed legislation accelerating the change to 8% to be effective as of July 1, 2020. As a result, the Alberta tax rate on business income for Alberta businesses in 2020 is 9%, representing a blended rate of 10% from January 1, 2020 through June 30, 2020 and 8% from July 1, 2020 through December 31, 2020.
In conjunction with our adoption of ASC 606 in 2018, we recognized a deferred tax liability associated with the previously deferred revenues net of previously deferred pipeline fees. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 was recovered during the year ended December 31, 2018. The deferred tax recovery of $3.8 million (representing C$4.9 million) for year ended December 31, 2018, was partially offset by the Canadian tax liability attributable to our earnings for the year ended December 31, 2018. Our financial results for the year ended December 31, 2019 were not affected by similar activities.
CARES Act
On March 27, 2020, the CARES Act was signed into law. The CARES Act is an emergency economic stimulus package enacted in response to the coronavirus outbreak which, among other measures, contains numerous income tax provisions. Some of these tax provisions are expected to be effective retroactively for tax years ending before the date of enactment. For us, the most significant change included in the CARES Act was the impact to U.S. net operating loss carryback provisions. U.S. net operating losses incurred in tax years 2018, 2019, and 2020 can now be fully carried back to the preceding five tax years and may be used to fully offset taxable income (i.e. they are not subject to the 80 percent net income offset limitation of Section 172 of the U.S. Tax Code).
As a result of these CARES Act changes, for the year ended December 31, 2020, we recognized a current tax benefit of $536 thousand for a claimable tax refund by carrying back to 2015 and 2017 U.S. net operating losses incurred in 2018, 2019, and 2020. We also recognized a one-time deferred tax expense of $46 thousand in the first quarter of 2020 due to the net effect of utilizing all U.S. net operating loss deferred tax assets and releasing the corresponding U.S. valuation allowance as of December 31, 2019. The tax impacts of the CARES Act were
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computed with the best available information, and will be adjusted after the 2020 U.S. tax return is finalized. However, we do not expect these adjustments to result in a material change to the tax provision in future periods.
Cash Distributions
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. The amount of distributions we pay under our cash distribution policy and the decision to make any distributions are determined by our general partner. We intend to pay distributions no later than 60 days after the end of each quarter. Given the uncertainty in the energy industry, as a proactive measure to strengthen our financial position and redeploy certain free cash to de-lever, the board of directors of our general partner elected in the first quarter of 2020 to reduce the quarterly distribution per unit declared by 70% as compared to the distribution for the fourth quarter of 2019. For the quarter ended December 31, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $0.111 per unit ($0.444 per unit on an annualized basis) on all of our units, which we paid on February 19, 2021 to unitholders of record at the close of business on February 10, 2021.
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RESULTS OF OPERATIONS
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 aid in resource allocation decisions and to assess operational performance.
The following table summarizes our operating results by business segment and corporate charges for each of the years indicated:
For the Year Ended December 31,
2020 2019 2018
(in thousands)
Operating income (loss)
Terminalling services $ 3,875  $ 32,334  $ 41,766 
Fleet services 73  20  (723)
Corporate and other (11,611) (11,721) (11,594)
Total operating income (loss) (7,663) 20,633  29,449 
Interest expense 8,932  12,006  11,358 
Loss (gain) associated with derivative instruments 3,896  1,420  (374)
Foreign currency transaction loss (gain) 267  365  (14)
Other expense (income), net (903) (336) 16 
Provision (benefit) from income taxes (41) 662  (2,669)
Net income (loss) $ (19,814) $ 6,516  $ 21,132 
Summary Analysis of Operating Results
Year ended December 31, 2020 compared to the year ended December 31, 2019
Changes in our operating results for the year ended December 31, 2020, as compared with our operating results for the year ended December 31, 2019, were primarily driven by:
activities associated with our terminalling services business including:
higher revenues resulting from rates on certain of our terminalling services agreements at our Hardisty Terminal that became effective July 1, 2019;
higher revenues associated with revenue that was recognized in 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty Terminal;
higher revenues due to higher rates at our Stroud Terminal during the last half of 2020 that are based on crude oil pricing index differentials;
lower operating income resulting from the conclusion of contracts at our Casper Terminal in August 2019 and lower subcontracted rail service costs due to lower throughput; and
higher operating costs resulting from a non-cash impairment of the goodwill associated with our Casper Terminal due to current economic conditions as a result of the COVID-19 pandemic, the overall downturn in the crude market and the decline in the demand for petroleum products.
a decrease in interest expense due to lower weighted average interest rates;
non-cash losses associated with declines in the fair value of our interest rate derivatives resulting from decreases in the forward interest rate index upon which the derivative values are based; and
an increase in our benefit from income taxes associated with our fleet services segment primarily related to net operating loss carrybacks made available by provisions in the CARES Act, coupled with a tax recovery on the Canadian tax filings associated with an adjustment in the appropriate taxable economic return from our Hardisty Terminal. This benefit was partially offset by a provision for income taxes associated with our terminalling
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services segment resulting from the recognition of previously deferred income for Canadian tax purposes at our Hardisty terminal recognized in 2020.
A more comprehensive discussion regarding our results of operations and financial condition for the year ended December 31, 2020 compared to the year ended December 31, 2019 is presented below. A discussion regarding our financial condition and results of operation for the year ended December 31, 2019 as compared with the year ended December 31, 2018 can be found under Item 7 in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on March 5, 2020, which is available free of charge on the SEC’s website at www.sec.gov and on our website at www.usdpartners.com.

RESULTS OF OPERATIONS - BY SEGMENT
TERMINALLING SERVICES
The following table sets forth the operating results of our Terminalling services business and the approximate average daily throughput volumes of our terminals for the periods indicated:
For the Year Ended December 31,
2020 2019 2018
(in thousands, except Bpd)
Revenues
Terminalling services $ 114,084  $ 106,753  $ 110,215 
Freight and other reimbursables 744  1,171  1,443 
Total revenues 114,828  107,924  111,658 
Operating costs
Subcontracted rail services 10,845  14,777  13,785 
Pipeline fees 23,862  20,971  21,679 
Freight and other reimbursables 744  1,171  1,443 
Operating and maintenance 14,650  11,848  6,375 
Selling, general and administrative 5,767  6,159  5,507 
Goodwill impairment loss 33,589  —  — 
Depreciation and amortization 21,496  20,664  21,103 
Total operating costs 110,953  75,590  69,892 
Operating income 3,875  32,334  41,766 
Foreign currency transaction loss (gain) 188  (90) 138 
Other expense (income), net (891) (324) 16 
Provision for (benefit from) income taxes 453  634  (2,709)
Net income $ 4,125  $ 32,114  $ 44,321 
Average daily terminal throughput (Bpd) 72,740  119,566  112,289 

Year ended December 31, 2020 compared to the year ended December 31, 2019
Terminalling Services Revenue
Revenue generated by our Terminalling services segment increased $6.9 million to $114.8 million for the year ended December 31, 2020, as compared with $107.9 million for the year ended December 31, 2019. This increase was due to increased revenue at our Hardisty Terminal resulting from revenue recognized during 2020 for contracted capacity that exceeded the transloading capacity of the terminal pursuant to an agreement that commenced in July 2019. This revenue was offset by additional operating costs incurred pursuant to an agreement with a related party for providing terminalling services for the additional capacity on our behalf at the same rate, on
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a per barrel basis, that we received as revenue in 2020. Higher rates included in some of our terminalling services agreements that became effective July 1, 2019 at our Hardisty Terminal due to our re-contracting efforts and increased rates in some of our contracts for the last half of 2020 also contributed to the increase in revenues. Additionally, we recognized revenue in 2020 that we previously deferred associated with the make-up right options we granted to customers of our Hardisty Terminal, as the likelihood that the make-up right options would be utilized in future periods was deemed remote and the make-up right options have now expired. In addition to the increases in revenue that were attributable to our Hardisty Terminal, we also had increased revenue at our Stroud Terminal in the last half of 2020 due to higher rates that are based on crude oil pricing index differentials. These increases in revenues were partially offset by lower revenue at our Casper Terminal resulting from the conclusion of a customer agreement in August 2019.
Our average daily terminal throughput decreased 46,826 bpd to 72,740 bpd for the year ended December 31, 2020, as compared with 119,566 bpd for the year ended December 31, 2019. Our throughput volumes decreased primarily due to a decrease in demand for export capacity by customers of our Hardisty Terminal that occurred during the second quarter of 2020 and continued throughout 2020, a portion of which drives the demand for deliveries to our Stroud Terminal and its connection to the Cushing oil hub. The decreased demand associated with our Hardisty Terminal resulted from the narrowed WCS to WTI pricing spreads during the last nine months of 2020, primarily as a result of the decline in global oil demand, as described in Overview and Recent Developments—Market Update—COVID-19 and Crude Oil Pricing Environment Update. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain primarily “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services.
Our terminalling services revenue for the year ended December 31, 2020, would have been $0.8 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the year ended December 31, 2020, was the same as the average exchange rate for the year ended December 31, 2019. The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7463 for the year ended December 31, 2020 as compared with 0.7538 for the year ended December 31, 2019.
Operating Costs
The operating costs of our Terminalling services segment increased $35.4 million to $111.0 million for the year ended December 31, 2020, as compared with $75.6 million for the year ended December 31, 2019. The increase is primarily attributable to an impairment of our goodwill recognized in the first quarter of 2020 at our Casper Terminal due to current economic conditions, an increase in operating and maintenance costs, higher pipeline fees and increased depreciation and amortization, partially offset by lower subcontracted rail services costs.
Our terminalling services operating costs for the year ended December 31, 2020, would have been $0.4 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the year ended December 31, 2020, was the same as the average exchange rate for the year ended December 31, 2019.
Subcontracted rail services. Our costs for subcontracted rail services decreased $3.9 million to $10.8 million for the year ended December 31, 2020, as compared with the year ended December 31, 2019, primarily due to the reduced throughput at our terminals that occurred during the last nine months of 2020, as discussed above.
Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty Terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty Terminal less direct operating costs. Our pipeline fees increased $2.9 million to $23.9 million for the year ended December 31, 2020, as compared with $21.0 million for the year ended December 31, 2019, primarily due to higher revenues at our Hardisty Terminal. Additionally, we recognized pipeline fees during the year ended December 31, 2020, associated with revenue that we previously deferred associated with the make-up right options we granted to customers of our Hardisty Terminal, since the likelihood that the make-up right options would be utilized in future periods was deemed remote and the make-up right options have now expired.
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Operating and maintenance. Operating and maintenance expense increased $2.8 million to $14.7 million for the year ended December 31, 2020, as compared with the year ended December 31, 2019. The increased operating and maintenance expenses are primarily due to expenses incurred pursuant to an agreement that commenced in July 2019 with a related party for providing terminalling services on our behalf to a customer of our Hardisty Terminal for contracted capacity that exceeds the current transloading capacity available at our Hardisty Terminal. These costs represent the same rate, on a per barrel basis, that we received as revenue from our third-party customer.
Goodwill impairment loss. In March 2020, we tested the goodwill associated with our Casper Terminal for impairment due to the overall downturn in the crude market and the decline in the demand for petroleum products. As a result of our impairment testing, we recognized an impairment loss of $33.6 million for the year ended December 31, 2020. Refer to Item 8. Financial Statements and Supplementary Data, Note 1. Organization and Description of Business and Note 9. Goodwill and Intangible Assets of this report for further discussion.
Depreciation and amortization. Depreciation and amortization expense increased $0.8 million to $21.5 million for the year ended December 31, 2020, as compared with $20.7 million for the year ended December 31, 2019. The increase is primarily due to a revised estimate of our asset retirement obligations, or ARO, that decreased depreciation and amortization expense by $0.6 million in the first quarter of 2019 associated with our decommissioned San Antonio Rail Terminal as compared to a revised ARO estimate that decreased depreciation and amortization by only $0.2 million during the second quarter of 2020 associated with the same terminal, coupled with an increase in depreciation associated with the outbound pipeline at our Casper Terminal that was placed into service in December 2019.
Other Expenses (Income)
Other expense (income), net. Other expense (income), net increased $0.6 million to $0.9 million for the year ended December 31, 2020, as compared with $0.3 million for the year ended December 31, 2019. This increase is primarily attributable to income that we earned in 2020 as an incentive for railcar movements of a customer at our Hardisty Terminal associated with new railroad incentive agreements.
Provision for (benefit from) income taxes. Our Canadian operations are conducted through entities that are subject to Canadian federal and Alberta provincial income taxes. The Canadian federal income tax on business income is currently 15%. In June 2019, the Canadian province of Alberta enacted a tax rate decrease that reduced the tax rate on business income from the previous rate of 12% to an ultimate rate of 8% effective for 2022. The reduction in the tax rate on business income was to be phased in over three years beginning with a reduction to a rate of 11% effective July 1, 2019, with further reductions of 1% in each successive year until it reached 8% on January 1, 2022. However, in December 2020, the Alberta government passed legislation accelerating the change to 8% to be effective as of July 1, 2020. As a result, the effective tax rate on business income for Alberta businesses in 2020 is 9%, representing a blended rate of 10% from January 1, 2020 through June 30, 2020 and 8% from July 1, 2020 through December 31, 2020.
We recognize income tax expense in our consolidated financial statements based upon enacted rates in effect for the periods presented. As such for the year ended December 31, 2020, income tax expense for our Canadian operations is determined based upon the combined federal and provincial income tax rate of 24%, representing a 15% federal income tax rate and a 9% provincial income tax rate. For the year ended December 31, 2019, income tax expense of our Canadian operations was determined based on the combined federal and provincial income tax rate of 26.5%. The combined income tax rate of 23%, representing a 15% federal income tax rate and an 8% provincial income tax rate, was used to compute the deferred income tax benefit, representing the impact of temporary differences that are expected to reverse in the future.
Our income taxes for the Terminalling services segment decreased by $0.2 million to $0.5 million for the year ended December 31, 2020, as compared with the year ended December 31, 2019. The decrease resulted primarily from a benefit recognized in the third quarter of 2020 associated with the 2019 Canadian tax filings and an adjustment to the appropriate economic return from the Hardisty Terminal, partially offset by a provision for income
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taxes associated with our terminalling services segment resulting from the recognition of previously deferred income for Canadian tax purposes at our Hardisty terminal recognized in 2020.
FLEET SERVICES
The following table sets forth the operating results of our Fleet services business for the periods indicated:
For the Year Ended December 31,
2020 2019 2018
(in thousands)
Revenues
Fleet leases $ 3,935  $ 3,935  $ 3,935 
Fleet services 1,113  1,118  1,483 
Freight and other reimbursables 167  679  2,150 
Total revenues 5,215  5,732  7,568 
Operating costs
Freight and other reimbursables 167  679  2,150 
Operating and maintenance 4,096  4,069  4,820 
Selling, general and administrative 879  964  1,321 
Total operating costs 5,142  5,712  8,291 
Operating income (loss) 73  20  (723)
Foreign currency transaction loss (gain) (14)
Other income, net (7) —  — 
Provision for (benefit from) income taxes (494) 28  43 
Net income (loss) $ 573  $ (17) $ (752)
Year ended December 31, 2020 compared to the year ended December 31, 2019
Operating Results
Revenues from our Fleet services segment decreased $0.5 million to $5.2 million for the year ended December 31, 2020, as compared to $5.7 million for the year ended December 31, 2019. The decrease in revenue was primarily attributable to fewer customer reimbursements to us for freight and other reimbursables charges that we have incurred on their behalf. The decrease in Freight and other reimbursables revenue was exactly offset by a corresponding decrease in Freight and other reimbursables operating costs for the same reason.
Our benefit for income taxes in the Fleet services segment increased $0.5 million to a benefit of $0.5 million for the year ended December 31, 2020, as compared with a provision of $28 thousand for the year ended December 31, 2019. This increase in benefit is due to a provision in the CARES Act that allows U.S. net operating losses incurred in tax years 2018, 2019, or 2020 to be carried back to the preceding five years and generate a tax refund. Under prior guidance, these net operating losses could only be carried forward.
Historically we have 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.
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CORPORATE ACTIVITIES
The following table sets forth our corporate charges for the periods indicated:
For the Year Ended December 31,
2020 2019 2018
(in thousands)
Operating costs
Selling, general and administrative $ 11,611  $ 11,721  $ 11,594 
Operating loss (11,611) (11,721) (11,594)
Interest expense 8,932  12,006  11,358 
Loss (gain) associated with derivative instruments 3,896  1,420  (374)
Foreign currency transaction loss (gain) 78  446  (138)
Other income, net (5) (12) — 
Benefit from income taxes —  —  (3)
Net loss $ (24,512) $ (25,581) $ (22,437)
Year ended December 31, 2020 compared to the year ended December 31, 2019
Costs associated with our corporate activities decreased by $1.1 million to $24.5 million for the year ended December 31, 2020, as compared to $25.6 million for the year ended December 31, 2019. Our interest expense costs decreased $3.1 million to $8.9 million for the year ended December 31, 2020, as compared to $12.0 million for the year ended December 31, 2019 primarily due to a decrease in interest expense that resulted from a decrease in the interest rates we were charged under our Credit Agreement. A higher non-cash loss of $3.9 million on our interest rate derivative for the year ended December 31, 2020, partially offset the decrease in interest expense, as compared to the loss of $1.4 million for the year ended December 31, 2019. In September 2020, we terminated our existing interest rate collar and simultaneously entered into a new interest rate swap that was made effective as of August 2020. In lieu of settling the liability value of the existing interest rate collar agreement of $3.5 million that existed at the time the agreement was terminated, the value of the liability was rolled into the fixed rate of the new interest rate swap agreement. The new interest rate swap is a five-year contract with a $150 million notional value that fixes our one-month LIBOR to 0.84% for the notional value of the swap agreement instead of the variable rate that we pay under our Credit Agreement. The swap settles monthly through the termination date in August 2025.

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LIQUIDITY AND CAPITAL RESOURCES
Our principal liquidity requirements include:
financing current operations;
servicing our debt;
funding capital expenditures, including potential acquisitions and the costs to construct new assets; and
making distributions to our unitholders
We have historically financed our operations with cash generated from our operating activities, borrowings under our Revolving Credit Facility and loans from our sponsor.
Liquidity Sources
We expect our ongoing sources of liquidity to include borrowings under our senior secured credit agreement, issuances of debt securities and additional partnership interests as well as cash generated from our operating activities. We believe that cash generated from these sources will be sufficient to meet our ongoing working capital and capital expenditure requirements and to make quarterly cash distributions at current levels for the next 12 months following the filing of this report.
Credit Agreement
Our Credit Agreement is a $385 million revolving credit facility (subject to limits set forth therein) with Citibank, N.A., as administrative agent, and a syndicate of lenders. Our Credit Agreement is a four year committed facility that initially matures on November 2, 2022. Our Credit Agreement provides us with the ability to request two one-year maturity date extensions, subject to the satisfaction of certain conditions, and allows us the option to increase the maximum amount of credit available up to a total facility size of $500 million, subject to receiving increased commitments from lenders and satisfaction of certain conditions. Our Credit Agreement contains customary representations, warranties, covenants and events of default for facilities of this type. In connection with establishing the Credit Agreement, which replaced the prior credit agreement entered into in October 2014, we incurred additional deferred financing costs of $2.9 million in 2018, which, in addition to any remaining deferred financing costs from our previous credit agreement, will be amortized over the four-year term of the Credit Agreement using the straight line method, which approximates the effective interest method.
Our Credit Agreement and any issuances of letters of credit are available for working capital, capital expenditures, general partnership purposes. The Credit Agreement includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the Credit Agreement are guaranteed by our restricted subsidiaries (as such term is defined therein) and are secured by a first priority lien on our assets and those of our restricted subsidiaries, other than certain excluded assets.
Our borrowings under the Credit Agreement bear interest at either a base rate plus an applicable margin ranging from 1.00% to 2.00%, or at a rate based on the London Interbank Offered Rate, or LIBOR, or a comparable or successor rate plus an applicable margin ranging from 2.00% to 3.00%. The applicable margin, as well as a commitment fee of 0.375% to 0.50% per annum on unused commitments under the Credit Agreement, will vary based upon our consolidated net leverage ratio, as defined in our Credit Agreement.
Our Credit Agreement contains affirmative and negative covenants that, among other things, limit or restrict our ability and the ability of our restricted subsidiaries to incur or guarantee debt, incur liens, make investments, make restricted payments, engage in certain business activities, engage in mergers, consolidations and other organizational changes, sell, transfer or otherwise dispose of assets, enter into burdensome agreements or enter into transactions with affiliates on terms that are not at arm’s length, in each case, subject to exceptions.
Additionally, we are required to maintain the following financial ratios, each determined on a quarterly basis for the immediately preceding four quarter period then ended (or such shorter period as shall apply, on an annualized basis): 
Consolidated Interest Coverage Ratio (as defined in the Credit Agreement) of at least 2.50 to 1.00;
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Consolidated Net Leverage Ratio of not greater than 4.50 to 1.00 (or 5.00 to 1.00 at any time after we have issued at least $150 million of certain qualified unsecured notes and for so long as the notes remain outstanding (the “Qualified Notes Requirement”)). In addition, upon the consummation of a Specified Acquisition (as defined in our Credit Agreement), for the fiscal quarter in which the Specified Acquisition is consummated and for two fiscal quarters immediately following such fiscal quarter (the “Specified Acquisition Period”), if timely elected by us by written notice to the Administrative Agent, the maximum permitted ratio shall be increased to 5.00 to 1.00 (or 5.50 to 1.00 if the Qualified Notes Requirement has been met); and
after we have met the Qualified Notes Requirement, a Consolidated Senior Secured Net Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.50 to 1.00 (or 4.00 to 1.00 during a Specified Acquisition Period).
Our Credit Agreement generally prohibits us from making cash distributions (subject to exceptions as set forth in the Credit Agreement). However, so long as no default exists or would be caused by making a cash distribution, we may make cash distributions to our unitholders up to the amount of our available cash (as defined in our partnership agreement).
The Credit Agreement contains events of default, including, but not limited to (and subject to grace periods in circumstances set forth in the Credit Agreement), the failure to pay any principal, interest or fees when due, failure to perform or observe any covenant (subject in some cases to certain grace periods or other qualifications), any representation, warranty or certification made or deemed made in the agreements or related loan documentation being untrue in any material respect when made, default under certain material debt agreements, commencement of bankruptcy or other insolvency proceedings, certain changes in our ownership or the ownership of our general partner, certain material judgments or orders, ERISA events or the invalidity of the loan documents. Upon the occurrence and during the continuation of an event of default under the agreements, the lenders may, among other things, terminate their commitments, declare any outstanding loans to be immediately due and payable and/or exercise remedies against us and the collateral as may be available to the lenders under the agreements and related documentation or applicable law.
As of December 31, 2020, we were in compliance with the covenants set forth in our Credit Agreement.
The weighted average interest rate on our outstanding indebtedness was 2.66% and 4.24% at December 31, 2020 and 2019, respectively, without consideration to the effect of our derivative contracts. We had Interest payable of $0.1 million and $0.6 million in “Other current liabilities” on our consolidated balance sheets at December 31, 2020 and 2019, respectively.

The following table presents our available liquidity as of the dates indicated:
December 31,
2020 2019
(in millions)
Cash and cash equivalents (1)
$ 3.0  $ 3.1 
Aggregate borrowing capacity under Credit Agreement
385.0  385.0 
     Less: Revolving Credit Facility amounts outstanding
197.0  220.0 
Available liquidity based on Credit Agreement capacity $ 191.0  $ 168.1 
Available liquidity based on Credit Agreement covenants (2)
$ 56.2  $ 31.9 
    
(1)    Excludes amounts that are restricted pursuant to our collaborative agreement with Gibson.
(2)    Pursuant to the terms of our Credit Agreement, our borrowing capacity is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to $53.2 million and $28.8 million of borrowing capacity available at December 31, 2020 and 2019, respectively.
Energy Capital Partners must approve any additional issuances of equity by us, and such determinations may be made free of any duty to us or our unitholders. Members of our general partner’s board of directors appointed by
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Energy Capital Partners must also approve the incurrence by us of additional indebtedness or refinancing outside of our existing indebtedness that is not in the ordinary course of business.
Cash Flows
The following table and discussion summarizes the cash flows associated with our operating, investing and financing activities for the periods indicated.
For the Year Ended December 31,
2020 2019 2018
(in thousands)
Net cash provided by (used in):
Operating activities
$ 45,814  $ 38,442  $ 45,129 
Investing activities
(484) (8,440) (8,580)
Financing activities
(44,992) (32,406) (36,890)
Effect of exchange rates on cash
(28) 705  (1,064)
Net change in cash and cash equivalents
$ 310  $ (1,699) $ (1,405)
Operating Activities
Net cash provided by operating activities increased by $7.4 million to $45.8 million for the year ended December 31, 2020, from $38.4 million for the year ended December 31, 2019. The increase in net cash provided by operating activities is primarily attributable to the changes in cash flow derived from our operating results as discussed above in Results of Operations. While our net loss for the year ended December 31, 2020 was $26.3 million more than our net income from 2019, the net loss for 2020 includes a significant amount of non-cash expenses that increase our net loss but do not decrease cash flow, such as our goodwill impairment loss and the increased loss associated with derivative instruments. The higher operating cash flow for the year ended December 31, 2020 as compared with 2019, is primarily due to the increase in revenues at our Hardisty and Stroud terminals as discussed above. The change in net cash provided by operating activities was also impacted by the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.
Investing Activities
Net cash used in investing activities decreased by $8.0 million to $0.5 million for the year ended December 31, 2020, as compared with the year ended December 31, 2019 primarily due to the construction of the outbound pipeline connection from our Casper Terminal to the Platte Terminal located at the termination point of the Express pipeline that was placed in service in December 2019.
Financing Activities
Net cash used for financing activities increased by $12.6 million to $45.0 million for the year ended December 31, 2020, from $32.4 million for the year ended December 31, 2019. Our net payments on our long-term debt during the year ended December 31, 2020 were $34 million higher than the net amounts we borrowed during the year ended December 31, 2019. Partially offsetting were decreased cash paid for distributions during the year ended December 31, 2020 as compared to the year ended December 31, 2019.
Cash Requirements
Our primary requirements for cash are: (1) financing current operations, (2) servicing our debt, (3) funding capital expenditures, including potential acquisitions and the costs to construct new assets, and (4) making distributions to our unitholders.
Capital Requirements
Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing
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facilities and to meet environmental and operational regulations. We also occasionally invest in our assets to expand their capacity or capability, such as the pipeline connection from our Casper Terminal to the Platte Terminal. We may incur unanticipated costs in connection with any expansion projects, which costs could be material or be incurred in periods after the project is completed.
Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital expenditures, or investment capital expenditures.
•    Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of terminals or other complementary midstream assets from USD or third parties and the construction or development of new terminals or additional capacity at our existing terminals to the extent such capital expenditures are expected to expand our operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is disposed of or abandoned.
•    Maintenance capital expenditures are cash expenditures made to maintain, over the long term, our operating capacity, operating income or our asset base. Examples of maintenance capital expenditures are expenditures to repair and refurbish our terminals.
•    Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures will largely consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand our operating capacity or operating income over the long term.
We have not experienced significant maintenance capital expenditures in prior years, however, as the age of our assets increase, we expect that costs we incur to maintain our assets in compliance with sound business practice, our contractual relationships and applicable regulatory requirements will likely increase. Some of these costs will be characterized as maintenance capital expenditures. We incurred $171 thousand and $216 thousand of maintenance capital expenditures during the year ended December 31, 2020 and December 31, 2019, respectively.
Our total expansion capital expenditures for the year ended December 31, 2020, amounted to $0.3 million. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated by our operation activities, borrowings under our Credit Agreement and the issuance of additional partnership interests or long-term debt.
Our total capital expenditures for the year ended December 31, 2019 of $8.4 million were primarily associated with the construction of an outbound pipeline connection from the Casper Terminal to the Platte Terminal.
Debt Service
We anticipate reducing our outstanding indebtedness to the extent we generate cash flows in excess of our operating, investing and distribution needs. During the year ended December 31, 2020, we received proceeds from borrowings of $12.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $35.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs. Subsequent to December 31, 2020 and as of March 2, 2021, we have made additional repayments of $5.0 million to the outstanding balance of our Revolving Credit Facility. As of March 2, 2021, we had amounts outstanding of $192.0 million under the Revolving Credit Facility and $193.0 million available for borrowing under
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the Revolving Credit Facility based on capacity that is subject to certain covenants. Refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt of this Annual Report for more information.
Distributions
Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis, and we do not have a legal obligation to distribute any particular amount per common unit.
For the quarter ended December 31, 2020, the board of directors of our general partner determined that we had sufficient available cash after the establishment of cash reserves and the payment of our expenses to distribute $0.111 per unit on all of our units. Our current quarterly distribution of $0.111 per unit equates to $3.0 million per quarter, or $12.1 million per year, based on the number of common and general partner units outstanding as of February 10, 2021. This distribution represents a decrease of 70% from the distribution with respect to the fourth quarter of 2019, and is consistent with the distribution declared for the first three quarters of 2020. Given the uncertainty in the energy industry, the board of directors made a proactive decision to strengthen our financial position by reducing our quarterly distributions and redeploying certain free cash flow to de-lever. During the second, third, and fourth quarters of 2020, we made net repayments of $6 million, $9 Million and $12 million respectively, of the outstanding balance of our Revolving Credit Facility. Subsequent to December 31, 2020 and as of March 2, 2021, we have made additional repayments of $5.0 million of the outstanding balance of our Revolving Credit Facility.
The board of directors of our general partner may change our distribution policy or suspend distributions at any time and from time to time. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, must approve any distributions made by us.
Other Items Affecting Liquidity
Credit Risk
Our exposure to credit risk may be affected by the concentration of our customers within the energy industry, as well as changes in economic or other conditions. Our customers’ businesses react differently to changing conditions. We believe that our credit-review procedures, customer deposits and collection procedures have adequately provided for amounts that may become uncollectible in the future.
Foreign Currency Exchange Risk
We currently derive a significant portion of our cash flows from our Canadian operations, particularly our Hardisty Terminal. As a result, portions of our cash and cash equivalents are denominated in Canadian dollars and are held by foreign subsidiaries, which amounts are subject to fluctuations resulting from changes in the exchange rate between the U.S. dollar and the Canadian dollar. We employ derivative financial instruments to minimize our exposure to the effect of foreign currency fluctuations, as we deem necessary based upon anticipated economic conditions.
SUBSEQUENT EVENTS
Refer to Note 22. Subsequent Events of our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report for a discussion regarding subsequent events.

Recent Accounting Pronouncements Not Yet Adopted
Refer to Note 2. Summary of Significant Accounting Policies of our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report for a discussion regarding recent accounting pronouncements that we have not yet adopted.

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OFF-BALANCE SHEET ARRANGEMENTS
In the normal course of business, we are a party to off-balance sheet arrangements relating to various master fleet services agreements, whereby we have agreed to assign certain payment and other obligations to third-party special purpose entities that are not consolidated with us. We have also entered into agreements to provide fleet services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk to us of non-payment by our customers, which would otherwise negatively impact our financial condition and results of operations. For more information on these special purpose entities, see the discussion of our relationship with the variable interest entities described in Note 12. Nonconsolidated Variable Interest Entities to our consolidated financial statements for the years ended December 31, 2020, 2019 and 2018 included in Part II, Item 8. Financial Statements and Supplementary Data of this Annual Report. Assets and liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements. As of the end of February 2021, the remaining railcar leases associated with our off-balance sheet arrangements were either assigned directly to our customers or expired. As such, we have terminated our relationship with the third-party special purpose entities discussed herein effective as of the end of February 2021.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our selection and application of accounting policies is an important process that has developed as our business activities have evolved and as new accounting pronouncements have been issued. Accounting decisions generally involve an interpretation of existing accounting principles and the use of judgment in applying those principles to the specific circumstances existing in our business. We make every effort to comply with all applicable accounting principles and believe the proper implementation and consistent application of these principles is critical. However, not all situations we encounter are specifically addressed in the accounting literature. In such cases, we must use our best judgment to implement accounting policies that clearly and accurately present the substance of these situations. We accomplish this by analyzing similar situations and the accounting guidance governing them and consulting with experts about the appropriate interpretation and application of the accounting literature to these situations.
In addition to the above, certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures with respect to contingent assets and liabilities. The basis for our estimates is historical experience, consultation with experts and other sources we believe to be reliable. While we believe our estimates are appropriate, actual results can and often do differ from these estimates. Any effect on our business, financial position, results of operations and cash flows resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
We believe our critical accounting policies and estimates discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involve complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit Committee of the board of directors of our general partner.
The following discussion relates to the critical accounting policies and estimates for USD Partners LP. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. The preparation of consolidated financial statements requires management to make judgments, assumptions and estimates based on the best available information at the time. The following accounting policies are considered critical because they are important to the portrayal of our financial condition and results, and involve a higher degree of complexity and judgment on the part of management. Actual results may differ based on the
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accuracy of the information utilized and subsequent events, some over which we may have little or no control. Significant estimates by management include the estimated lives of depreciable property and equipment, recoverability of long-lived assets and goodwill, and provision or benefit for income taxes.
Revenue
We recognize revenue from contracts with customers by applying the provisions of ASC 606, Revenue from Contracts with Customers. We recognize revenue under the core principle to depict the transfer of control to our customers of goods or services in an amount reflecting the consideration for which we expect to be entitled. In order to achieve the core principle, we apply the following five step approach:
(1)    identify the contract with a customer;
(2)    identify the performance obligations in the contract;
(3)    determine the transaction price;
(4)     allocate the transaction price to the performance obligations in the contract; and
(5)     recognize revenue when a performance obligation is satisfied.
We define a performance obligation as a promise in a contract to transfer a distinct good or service to the customer, which also represents the unit of account under ASC 606. We allocate the transaction price in a contract to each distinct performance obligation, which we recognize as revenue when, or as, the performance obligation is satisfied. For contracts with multiple performance obligations, we allocate the transaction price in the contract to each performance obligation using our best estimate of the standalone selling price for each distinct good or service in the contract, utilizing market-based and cost-plus margin inputs. We have elected to account for sales taxes received from customers on a net basis.
We apply the right-to-invoice practical expedient to contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.
Terminalling Services Revenues
We derive a majority of our revenues from contracts to provide terminalling services, which include pipeline transportation, storage, loading and unloading of crude oil and related products from and into railcars and trucks, as well as the transloading of biofuels from railcars into trucks. Our terminalling services agreements for crude oil and related products are generally established under multi-year, take-or-pay provisions that require monthly payments from our customers for their minimum monthly volume commitments in exchange for our performance of the terminalling services enumerated above. Our terminalling services for biofuels typically require monthly payments for actual volumes handled. Variable consideration, such as volume-based pricing, included in our agreements is typically resolved within the applicable accounting period.
We recognize revenue for the terminalling services we provide based upon the contractual rates set forth in our agreements related to throughput volumes. We recognize revenue over time as we render services based on the throughput delivered as this best represents the value we provide to customers for our services. All of the contracted capacity at our Hardisty Terminal and Stroud Terminal is contracted under multi-year agreements that contain “take-or-pay” provisions where we are entitled to the payment of minimum monthly commitment fees from our customers, regardless of whether the specified throughput volumes to which the customer committed is achieved.
Our terminalling services agreements at our Hardisty Terminal and Stroud Terminal generally grant our customers make-up rights that allow them to load volumes in excess of their minimum monthly commitment in future periods, without additional charge, to the extent capacity is available for the excess volume. The make-up rights typically expire, if unused, in subsequent periods up to 12 months following the period for which the volumes were originally committed. We currently recognize substantially all of the amounts we receive for minimum commitment fees as revenue when collected, since breakage associated with these make-up rights options has varied between 97% and 100% based on our experience and expectations around usage of these options. Breakage rates are regularly evaluated and modified as necessary to reflect our current expectations and experience. If we do not expect to be entitled to a breakage amount, we defer the recognition of revenue associated with volumes that are below the
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minimum monthly commitment until we determine that the likelihood that the customer will be able to make up the minimum volume is remote or the make-up right expires. If we expect to be entitled to a breakage amount, we estimate expected breakage and recognize the expected breakage amount as revenue in proportion to the trend of rights exercised by the customer.
Fleet Services Revenues
Our fleet services contracts provide for the sourcing of railcar fleets and related logistics and maintenance services. We allocate revenue between the lease and service components based on the relative standalone values, typically utilizing market-based and cost-plus margin estimates, and account for each component under the applicable accounting guidance. We record revenues for fleet leases on a gross basis, since we are deemed the primary obligor for the services.
We recognize revenue for fleet leases and related party administrative services ratably over the contract period as services are consistently provided throughout the period. Revenue for reimbursable costs is recognized on a gross basis on our consolidated statements of operations as “Freight and other reimbursables,” as the costs are incurred. We have deferred revenues for amounts collected in advance from customers in our Fleet services segment, which we will recognize as revenue as the underlying services are performed pursuant to the terms of our contracts. We have prepaid rent associated with these deferred revenues on our railcar leases, which we will recognize as expense as these railcars are used.
Capitalization Policies and Depreciation Methods
We record property and equipment at its original cost, which we depreciate on a straight-line basis over the estimated useful lives of the assets, which range from three to 30 years. Our determination of the useful lives of property and equipment requires us to make various assumptions when the assets are acquired or placed into service about the expected usage, normal wear and tear and the extent and frequency of maintenance programs. Expenditures for repairs and maintenance are charged to expense as incurred, while improvements that extend the service life or capacity of existing property and equipment are capitalized. Upon the sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized in our operating results.
During construction we capitalize direct costs, such as labor, materials and overhead, as well as interest cost we may incur on indebtedness at our incremental borrowing rate.
Impairment of Long-lived Assets
We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable.
We consider a long-lived asset to be impaired when the sum of the estimated, undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset, or a significant change in the asset’s physical condition or use.
When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss is recognized to the extent the carrying amount exceeds the estimated fair value of the long-lived asset.
We determined the overall downturn in the crude market and the decline in the demand for petroleum products, which could lead to delays or reduction of expected throughput levels and changes in expectations for current and future contracts in our terminalling services at the Casper Terminal was an event that required us to evaluate our Casper Terminal asset group for impairment. We tested the fair value of our Casper Terminal assets by
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using projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper Terminal asset.
The critical assumptions underlying our projections included the following:
1)a range of incremental volumes expected at our Casper Terminal of approximately 4,000 to 25,000 bpd for terminalling and storage services resulting from the anticipated successful completion of the Enbridge DRA project
2)expected volumes for our blended services business for distribution to local refiners;
3)a 15 year remaining useful life of the primary asset, represented by our property and equipment of the Casper Terminal asset group; and
4)a residual value of 8.0x projected cash flows for the Casper Terminal at the end of the 15 year remaining life of the primary asset.
Our projections of the undiscounted cash flows expected to be derived from the operation and disposition of the Casper Terminal asset group exceeded the carrying amount of the asset group as of March 31, 2020, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying amount of the Casper Terminal asset group. Accordingly, we did not recognize any impairment of our Casper Terminal asset.
To the extent that our assumptions as set forth above do not materialize, our projections of future financial performance underlying our cash flow projections for the Casper Terminal could yield undiscounted cash flows and a fair value that indicate our long-lived assets are impaired. Moreover, these assumptions may change over time in response to the effects of the COVID-19 pandemic and the state of the commodity markets, which are inherently uncertain and difficult to predict.
We have not observed any events or circumstances subsequent to our analysis at March 31, 2020 that would suggest the fair value of our Casper Terminal asset is below its carrying amount as of December 31, 2020.
Assessment of Recoverability of Goodwill
Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. Historically, goodwill was only included in our Terminalling services segment as part of our Casper Terminal reporting unit.
Historically, we did not amortize goodwill, but tested it for impairment annually based on the carrying amounts of our reporting units on the first day of the third quarter of each year or more frequently if impairment indicators arose that suggested the carrying amount of goodwill might be impaired. Our assessment of the recoverability of goodwill is highly subjective due to frequent changes in economic conditions underlying the assumptions upon which the valuations are based and global factors affecting the prices for various grades of crude oil and demand for our services.
In assessing our ability to recover the carrying amount of goodwill, we made critical assumptions that included but were not limited to:
1)our projections of future financial performance;
2)our expectations for contract renewals for existing and additional capacity with current customers;
3)our ability to expand our services and attract new customers;
4)our expected market weighted average cost of capital;
5)an expected range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics; and
6)an expected range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses.
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We recognized an impairment loss when the carrying amount of a reporting unit exceeded its implied fair value. We reduced the carrying amount of goodwill to its fair value at the time we determined that an impairment has occurred.
Our goodwill originated from our acquisition of the Casper Terminal in November 2015 and was wholly attributed to this reporting unit. We measured the fair value of our Casper Terminal reporting unit using customary business valua