Item 1. Business

OVERVIEW

We are a fee-based, growth-oriented master limited partnership formed 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.

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. USDG has also recently completed an expansion project at the Partnership’s Hardisty terminal, also referred to as Hardisty South, which adds one 120-railcar unit train of transloading capacity per day, or approximately 75,000 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:

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 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. During 2018, we successfully renewed and extended multiple agreements on a long-term basis at our Hardisty Terminal. Additionally, we executed a multi-year terminal services agreement as well as other short-term agreements in furtherance of our hub strategy at our Casper terminal. As of December 31, 2018, the volume-weighted average remaining contract life of our take-or-pay terminal service agreements was approximately 3.0 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 3.3 years as of December 31, 2018.

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 960,000 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  2018 , USD has loaded or handled through its terminal network a total of approximately 243 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 $19.0 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 45 investment platforms with investments in the power generation, electric transmission, midstream and renewable 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, 2018 . The ownership percentages referred to below illustrate the relationships among us, our general partner, USDG, USD, Energy Capital Partners and Goldman Sachs, and excludes 1,205,909 Phantom Units outstanding under our Long-Term Incentive Plan at December 31, 2018 .

BUSINESS STRATEGY

Our primary business objective is to continue increasing the quarterly cash distributions we make to our unitholders over time. We intend to accomplish this objective by executing the following business strategies:

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 and total assets for each segment, refer to Note 14. 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 16. 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 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 10 MMbbls of crude oil storage facilities at Hardisty and another 2.5 MMbbls under construction, 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 six customers, including major integrated oil companies, refiners and marketers. Our contracts with customers are subject to renewal provisions as follows:

We are currently in discussions to extend the agreements that expire in 2019 and 2020.

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. One of our agreements will renew for a one-year term upon written election by the customer at least two years prior to the end of the initial term, while another agreement contains no automatic renewal provisions. Each 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 six 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.

Sponsor Initiatives at Hardisty

Hardisty South Expansion

Current market demand for the services provided at our Hardisty terminal exceeds our available capacity as substantially all of the terminal’s capacity was previously contracted for by customers under multi-year agreements through mid-2019 and mid-2020.

In June 2018, USD Group LLC, or USDG, announced that it executed a five-year, take-or-pay terminalling services agreement with a high quality refiner customer. The agreement is for trans-loading capacity at the Hardisty rail terminal. This new agreement provided commercial support for the construction of additional capacity at the Hardisty terminal pursuant to USDG’s existing development rights.

Pursuant to the increased market demand for terminalling services at Hardisty, USDG initiated and completed the Hardisty South expansion (“Hardisty South”). 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 unit train per day, or approximately 75,000 barrels per day, of takeaway capacity to the terminal by modifying the existing loading rack and building additional infrastructure and trackage. The project was placed into service during January 2019. 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 USDG.

Our sponsor is also pursuing long-term solutions to transport heavier grades of crude oil produced in Western Canada, which our sponsor believes will maximize benefits to producers, refiners and railroads. Any such development project would be wholly-owned by USDG and would be subject to our existing right of first offer with respect to midstream projects developed by USDG.

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 Central Rail, which handles deliveries from both the BNSF Railway, or BNSF, and the Union Pacific Railroad, or UP.

Concurrent with the Stroud acquisition, we entered into a multi-year, take-or-pay terminalling services agreement with an investment grade multi-national energy company for the use of approximately 50% of the available capacity at the Stroud terminal. The term of this agreement is scheduled to conclude on June 30, 2020, unless otherwise renewed or extended. 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 six 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.

In addition, we entered into a Marketing Services Agreement, or MSA, effective as of May 31, 2017, with USD Marketing LLC, or USDM, an affiliate of USDG, 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. USDM is obligated to fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional throughput. As such, a permanent steaming solution at the Stroud terminal to alleviate operational railcar unloading issues that resulted from cold weather at the terminal was constructed by USDM. The construction of the steaming equipment was completed in July 2018 and contributed to us. In the event that our contract with the initial Stroud customer is not renewed and expires in June 2020, the same marketing rights will 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 terminal 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.

Pursuant to the MSA, during March and April 2018, the Stroud customer secured the remaining available capacity at the Stroud terminal from USDM, for periods beginning in the second quarter of 2018 and ending in June 2019 and January 2020.

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. Additionally, 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 developed by USDG .

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 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 is generally loaded onto railcars and then transported to end markets by the BNSF, in either manifest or unit train shipments. The terminal’s location on the BNSF’s main line offers advantaged transportation costs to key U.S. refining markets where several customer-preferred destinations are also served by the BNSF. Shipping with a single Class 1 railroad reduces railroad switching fees and enables faster train turn-times, thus improving railcar fleet utilization.

Effective September 2018, we entered into a three-year agreement at our Casper Terminal with a multi-national, investment grade customer, discussed in further detail below. The agreement supports the construction of an outbound pipeline connection from the Casper Terminal to complement the terminal’s current inbound pipeline connection to the Express Pipeline, and an additional storage tank to facilitate blending and staging operations for the customer. The customer will utilize an existing tank at the Casper Terminal for a three-year term and a second tank, once constructed or available, for another three-year term. The construction of the second tank, if needed, is expected to be completed in the second half of 2019.

We provide service at the Casper terminal under two terminal services agreements with a high quality, investment grade refiner and a new multi-national investment grade customer. Under the terminal services agreement with the

refiner customer, our customer is obligated to pay the greater of a minimum monthly commitment fee or a throughput fee based on the actual volume of crude oil loaded. If a customer loads fewer unit trains or barrels than its allotted amount in any given month, that customer will receive a credit which may be used to offset future throughput fees in excess of the minimum monthly commitment fees, to the extent capacity is available for the excess volume. Unused credits generally expire if not used by the end of each calendar quarter. The multi-year agreement with the multi-national customer contains take-or-pay terms for terminalling and storage services and variable fees associated with actual throughput volumes and other services. We have also entered in to a one-year terminalling services agreement at our Casper terminal, effective January 1, 2019, which contains take-or-pay terms for 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.

Following the expiration of customer contracts with us in August 2017 and December 2018, we have available capacity to accommodate spot activity and new customer agreements, both of which we are actively pursuing.

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 terms ranging from five to nine years. We do not own any railcars. As of December 31, 2018 , our fleet consisted of 1,683 railcars, which we leased from various railcar manufacturers and financial entities, including 1,308 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet services agreements for 1,483 of the railcars to other parties, but we have retained certain rights and obligations with respect to the provision of fleet services regarding these railcars. Substantially all of our current railcar fleet is dedicated to customers of our Hardisty terminal, including an affiliate of USDG. In the aggregate, our master fleet services agreements have a weighted-average remaining contract life of 3.3 years as of December 31, 2018 .

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 railcar use and a component for fleet services. The master fleet services agreements will expire unless notice to renew is provided by our customers.

All of our railcars currently in service were constructed in 2013 or later. The average age of our fleet currently in service is approximately five 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, 2018 , our railcar fleet consisted of a mix of 1,308 C&I railcars and 375 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.

Through the end of 2018, the leases on approximately 1,130 railcars expired or were terminated. The return of these leased railcars reduced the operating income or cash flows we have historically derived from this business. This decrease has occurred as our customers have become more accustomed to shipping crude oil by rail and have obtained their railcars directly from manufacturers. Should market conditions change, we would potentially assist with the procurement and management of railcars on behalf of our customers again in the future.

BENEFITS OF RAIL

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 to 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.

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 an 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 October 15, 2014, closing of our IPO. Additional information about the omnibus agreement and the right of first offer are included in Note 12. 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 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 project to expand the Hardisty 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 and Stroud terminals 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 and Stroud terminals.

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 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. 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, 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 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.

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 CO ₂ , 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 are to become effective in 2020. In June 2017, however, President Trump stated that the United States intends to withdraw from the Paris treaty, but may enter into a future international agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United Nations of its intent to withdraw from the Paris treaty unless it renegotiated. The Paris treaty provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris treaty or a separately negotiated agreement are unclear at this time. 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. 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 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. The EPA and the U.S. Army Corps of Engineers released a rule to revise the definition of “waters of the United States,” or WOTUS, for all Clean Water Act programs, which went into effect in August 2015 and defines the jurisdiction reach of the Clean Water Act programs. The EPA has instituted rulemakings to both delay the effective date of this rule and repeal the rule. Federal district court decisions have preserved the stay in a majority of states, which remain subject to pre-2015 regulated waters regulations, whereas the stay has been enjoined in a minority of states. Litigation surrounding this rule is ongoing. More recently,

on December 11, 2018, the EPA and the Corps released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of waters of the United States; the revised rule has not yet been finalized.

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.  

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 manage a large 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 1,683 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 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. Currently this Final Rule has been transmitted to the Federal Register for publication and will take effect 180 days after the publication date in the Federal Register.

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, 2018, we had 375 railcars which will require retrofitting to comply with the jacketed CPC-1232 rules. The remaining cars already meet the requirements of the directive. We believe that the current retrofit timelines that have been released to date should provide us with sufficient time to make any changes to our railcar fleet that is required due to these new regulations. Were DOT 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.  

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 and Stroud terminals 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 pipeline, 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 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 2019.

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 is expected to release its final safety standards for hazardous liquid pipelines in 2019. Although we cannot predict the final form those standards will take, we do not anticipate that we would be impacted by either of these regulatory initiatives to any greater degree than other similarly situated competitors upon their going into effect.

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 highest 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 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. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates were permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. 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 pipeline. 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 2005, FERC issued a policy statement stating that it would permit common carriers, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are organized as pass-through entities, it still entails rate risk due to the FERC’s case-by-case review approach.

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 tax costs.

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:

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.

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.  

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 standard 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 currently are implementing 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.

EMPLOYEES

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 approximately 85 employees performing services for our operations. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

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.