0001610682-15-000030.txt : 20150331 0001610682-15-000030.hdr.sgml : 20150331 20150330181630 ACCESSION NUMBER: 0001610682-15-000030 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 20141231 FILED AS OF DATE: 20150331 DATE AS OF CHANGE: 20150330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: USD Partners LP CENTRAL INDEX KEY: 0001610682 STANDARD INDUSTRIAL CLASSIFICATION: RAILROAD SWITCHING & TERMINAL ESTABLISHMENTS [4013] IRS NUMBER: 000000000 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-36674 FILM NUMBER: 15735839 BUSINESS ADDRESS: STREET 1: 811 MAIN STREET STREET 2: SUITE 2800 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 713-249-0426 MAIL ADDRESS: STREET 1: 811 MAIN STREET STREET 2: SUITE 2800 CITY: HOUSTON STATE: TX ZIP: 77002 10-K 1 usdp201410k.htm USDP 12312014 10-K USDP201410K

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x No ¨ 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer ¨
Accelerated Filer ¨
Non-Accelerated Filer x
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of June 30, 2014, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any domestic exchange or over-the-counter market.
As of March 24, 2015, the registrant has outstanding 10,213,545 common units; 10,463,545 subordinated units; 220,000 Class A units; and 427,083 general partner units.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
 



TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unless the context otherwise requires, all references in this Annual Report on Form 10-K (this “Annual Report” or this “Form 10-K”) to “USD Partners,” “USDP,” “the Partnership,” “we,” “us,” “our,” or like terms used in the present tense or prospectively (beginning October 15, 2014) refer to USD Partners LP and its subsidiaries. References in this Annual Report to “the Predecessor,” “we,” “our,” “us,” or like terms, when used in a historical context (periods prior to October 15, 2014), refer to the following subsidiaries, collectively, that were contributed to USD Partners in connection with our Initial Public Offering of 9,120,000 common units that we completed on October 15, 2014, (the “IPO”): San Antonio Rail Terminal LLC (“SART”), USD Rail LP, USD Rail Canada ULC, USD Terminals Canada ULC, West Colton Rail Terminal LLC (“WCRT”), USD Terminals International, and USD Rail International. The Predecessor also includes the membership interests in the following five subsidiaries of USD which operated crude oil rail terminals that were sold in December 2012: Bakersfield Crude Terminal LLC, Eagle Ford Crude Terminal LLC, Niobrara Crude Terminal LLC, St. James Rail Terminal LLC (“SJRT”), and Van Hook Crude Terminal LLC, collectively known as (the “Discontinued Operations”).

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) “our sponsor” and “USD” refer to US Development Group LLC, a Delaware limited liability company, and where the context requires, its subsidiaries; (iii) “USD Group LLC” refers 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.

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) changes in general economic conditions; (2) the effects of competition, in particular, by pipelines and other terminalling facilities; (3) shut-downs or cutbacks at upstream production facilities, or refineries, petrochemical plants or other businesses to which we transport products; (4) the supply of, and demand for, crude oil and biofuel rail terminalling services; (5) our limited history as a separate public partnership; (6) the price and availability of debt and equity financing; (7) hazards and operating risks that may not be covered fully by insurance; (8) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (9) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (10) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase our costs; and (11) our ability to successfully identify and finance acquisitions and other growth opportunities.
 

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For additional factors that may affect 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 U.S. Securities and Exchange Commission’s (SEC), website (www.sec.gov) and at our website (www.usdpartners.com).


iii


Glossary
The following abbreviations, acronyms and terms used in this Form 10-K are defined below:
AOCI
 
Accumulated other comprehensive income
API Gravity
 
American Petroleum Institute Gravity
Bbl or bbl
 
Barrels, common unit of measure in the oil industry, which equates to 42 US gallons
Bitumen
 
A dense, highly viscous, petroleum-based hydrocarbon that is found in deposits such as oil sands
Bpd
 
Barrels per day
CAA
 
Clean Air Act, as amended
CAD
 
Amount denominated in Canadian dollars
CWA
 
Clean Water Act, as amended
Diluent
 
Refers to lighter hydrocarbon products such as natural gasoline or condensate that is blended with heavy crude oil to allow for pipeline transportation of heavy crude oil
DOT
 
U.S. Department of Transportation
EBITDA
 
Earnings before Interest, Taxes, Depreciation and Amortization
EPA
 
Environmental Protection Agency
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. Used in the United States as a gasoline octane enhancer and oxygenate
Exchange Act
 
Securities Exchange Act of 1934, as amended
FERC
 
Federal Energy Regulatory Commission
General Partner
 
USD Partners GP LLC, the general partner of the Partnership
GHG
 
Greenhouse gases such as carbon dioxide
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
Hydrocarbon-by-rail
 
The transportation of hydrocarbons, such as crude oil and ethanol, by rail, particularly through the use of unit trains
Legacy railcar
 
A 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
LIBOR
 
London Interbank Offered Rate—British Bankers’ Association’s average settlement rate for deposits in United States dollars
Manifest train
 
Trains that are composed of mixed cargos and often stop at several destinations
Mbpd
 
A thousand barrels per day
MMbbls
 
A million barrels
MMbpd
 
A million barrels per day
NGA
 
Natural Gas Act
NGL or NGLs
 
Natural gas liquids
NYMEX
 
The New York Mercantile Exchange where commodity futures, options contracts and other energy futures are traded
NYSE
 
New York Stock Exchange
IPO
 
The initial public offering of 9,120,000 of our common units which priced on October 8, 2014
Oil sands
 
Deposits of loose sand or partially consolidated sandstone that is saturated with highly viscous bitumen
Partnership Agreement
 
Second Amended and Restated Agreement of Limited Partnership of USD Partners LP
Partnership
 
USD Partners LP and its consolidated subsidiaries
SEC
 
U.S. Securities and Exchange Commission
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
U.S. GAAP
 
U.S. Generally Accepted Accounting Principles

iv


PART I
Item 1. Business
OVERVIEW

We are a fee-based, growth-oriented master limited partnership formed in 2014 by USD to acquire, develop and operate energy-related rail terminals and other high-quality and complementary midstream infrastructure assets and businesses. On October 15, 2014, we completed the IPO of our common units which trade on the NYSE under the ticker symbol USDP. In connection with the IPO, the ownership interests in each of USD's subsidiaries that own or operate the Hardisty, San Antonio and West Colton rail terminals and our railcar business were conveyed to us.

We generate substantially all of our operating cash flow by charging fixed fees for terminalling and railcar fleet services for energy-related products. We do not take ownership of the underlying commodities that we handle nor do we receive any payments from our customers based on the value of such commodities. Our assets consist primarily of: (i) an origination crude-by-rail terminal in Hardisty, Alberta, Canada, with capacity to load up to two 120-railcar unit trains per day and (ii) two destination unit train-capable ethanol rail terminals in San Antonio, Texas, and West Colton, California, with a combined capacity of approximately 33,000 bpd. Our rail terminals provide critical infrastructure allowing our customers to transport energy-related products from multiple supply regions to various demand markets. In addition, we provide railcar services through the management of a railcar fleet consisting of approximately 3,099 active railcars, as of December 31, 2014, that are committed to customers on a long-term basis, with an additional 650 railcars expected to be available for service during the first half of 2015. Rail transportation of energy-related products provides efficient and flexible access to key demand markets on a relatively low fixed-cost basis, and as a result, has become an important part of North American midstream infrastructure.
 
The following table provides a summary of information about our assets:
Terminal Name
 
Location
 
Designed
Capacity
 
(Bpd)
 
Commodity
Handled
 
Primary
Customers
 
Terminal
Type 
Hardisty rail terminal
 
Alberta, Canada
 
~172,629(1)
 
Crude Oil
 
Producers/Refiners
/Marketers
 
Origination
San Antonio rail terminal
 
Texas, U.S.
 
20,000
 
Ethanol
 
Refiners/Blenders
 
Destination
West Colton rail terminal
 
California, U.S.
 
13,000
 
Ethanol
 
Refiners/Blenders
 
Destination
 
 
 
 
205,629
 
 
 
 
 
 
 
(1)
Based on two 120-railcar unit trains comprised of 31,800 gallon (approximately 757 barrels) railcars being loaded at 95% 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.

The crude oil terminalling services provided by our Hardisty rail terminal generates the vast majority of our operating cash flow. Substantially all of the capacity at our Hardisty rail terminal is contracted under multi-year, take-or-pay terminal services agreements with seven customers. Approximately 83% of the contracted utilization at our Hardisty rail terminal is with subsidiaries of five investment grade companies, which include major integrated oil companies, refiners and marketers. Each of the terminal services agreements with our Hardisty rail terminal customers has an initial contract term of five years. The initial terms of these agreements commenced between June 30, 2014 and October 1, 2014. Each of these agreements is subject to inflation-based rate escalators, and all but one have automatic renewal provisions. In addition to terminalling services, we provide customers access to railcars under fleet services agreements. These agreements are typically executed in conjunction with commitments to use our rail terminals, where customers commit to use our railcars and fleet management services on a take-or-pay basis for periods ranging from five to nine years.

One of our key strengths is our relationship with our sponsor, USD. USD is a growth-oriented developer, builder, operator and manager of energy-related infrastructure and was among the first companies to successfully develop the

1




hydrocarbon-by-rail concept. USD has developed, built or operated 14 unit train-capable origination and destination terminals with an aggregate capacity of over 725,000 bpd. Ten of these terminals were subsequently sold in multiple transactions for an aggregate sales price of over $740 million. From January 2006 through December 2014, USD has loaded or handled through its terminal network a total of over 155 MMbbls of liquid hydrocarbons. USD also has a nationally recognized safety record with no reportable spills at any of its terminals since its inception, as defined by the DOT Pipeline and Hazardous Materials Safety Administration ("PHMSA"). USD is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD’s management team members.

On September 19, 2014, Energy Capital Partners made a significant investment in USD, and has indicated an intention to invest an additional $1.0 billion of equity capital in USD, subject to market and other conditions, over five years to support USD’s growth and expansion plans. Energy Capital Partners, together with its affiliates and affiliated funds, is a private equity firm with over $13.0 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 24 investment platforms with investments in the power generation, electric transmission, midstream and renewable sectors of the energy industry, including Summit Midstream Partners, LP, another public master limited partnership.

USD 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 rail terminals and other high-quality and complementary midstream infrastructure assets and businesses from both USD 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 shows our simplified organization and ownership structure as of December 31, 2014. The ownership percentages referred to below illustrate the relationships among us, our general partner, USD Group LLC, USD, Energy Capital Partners and Goldman Sachs, and excludes 415,608 phantom units granted under our Long Term Incentive Plan during the first quarter of 2015.


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3




BUSINESS STRATEGY
Our primary business objective is to increase 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.    Substantially all 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 executing fee-based agreements with existing and new customers.
Pursue accretive acquisitions.    We intend to pursue strategic and accretive acquisitions of energy-related rail terminals and high-quality and complementary midstream infrastructure assets and businesses from USD and third parties. We will consistently evaluate and monitor the marketplace to identify acquisitions within our existing geographies and in new regions that may be pursued independently or jointly with USD.
Pursue organic growth initiatives.    We intend to pursue organic growth projects and seek operational efficiencies that complement, optimize or improve the profitability of our assets. For example, we are currently in the process of seeking permits to construct a pipeline directly from our West Colton rail terminal to local gasoline blending terminals, which if approved and 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 efficient and effective 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 all government safety regulations and are in compliance with all recently enacted orders regarding the movement of crude-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 and total assets for each segment, as well as by geographic area, refer to Note 11. 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 12. 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
We generate substantially all of our operating cash flow by charging fixed fees for handling energy-related products and providing related services. We do not take ownership of the underlying products that we handle nor do we receive any payments from our customers based on the value of such products. Thus, we have no direct exposure to risks associated with fluctuating commodity prices, although these risks could indirectly influence our activities and results of operations over the long term.
Our Terminalling services business consists of the following operations:

Hardisty Rail Terminal
 
Our Hardisty rail terminal is an origination terminal that commenced operations on June 30, 2014 and loads various grades of Canadian crude oil received from Alberta’s Crude Oil Basin through the Hardisty hub. The Hardisty hub is one of the major crude oil supply centers in North America and is an origination point for export pipelines to the United States. The Hardisty rail terminal can load up to two 120-railcar unit trains per day and consists of a fixed loading rack with 30 railcar loading positions, a unit train staging area and loop tracks capable of holding five unit

4




trains simultaneously. This facility 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 rail terminal is designed to receive inbound deliveries of crude oil directly through a pipeline connected to the Hardisty storage terminal owned by Gibson Energy Inc. ("Gibson"). Gibson, one of the largest independent midstream companies in Canada, has 5.5 MMbbls of storage in Hardisty and has access to most of the major pipeline systems in the Hardisty hub. Gibson has announced that it is constructing an additional 1.6 MMbbls of storage capacity at its Hardisty terminal, 0.5 MMbbls of which is expected to be in service by the end of 2015, with the remaining 1.1 MMbbls of capacity available by late 2016. The direct pipeline connection, in addition to the terminal location, provides our Hardisty rail terminal with efficient access to the major producers in the region. Our Hardisty rail terminal is connected to Canadian Pacific Railroad’s North Main Line, a high capacity line with the ability to connect to all the key refining markets in 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 rail terminal, which we operate and maintain. Gibson is responsible for transporting product through the pipeline to our Hardisty rail terminal. The Gibson storage terminal is the exclusive means by which our Hardisty rail terminal can receive crude oil. Subject to certain limited exceptions regarding manifest train facilities, this pipeline to our Hardisty rail terminal is also the exclusive means by which crude oil from Gibson’s storage terminal may be transported by rail. All revenues associated with the pipeline and our Hardisty rail terminal are split between us and Gibson 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 rail terminal to a third party. The agreement has a 20-year term and will expire 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 rail terminal is contracted under multi-year, take-or-pay terminal services agreements with seven customers. Approximately 83% of our Hardisty rail terminal’s utilization is contracted with subsidiaries of five investment grade companies that include major integrated oil companies, refiners and marketers. Each of the terminal services agreements with our Hardisty rail terminal customers has an initial contract term of five years. The initial terms of these agreements commenced between June 30, 2014 and October 1, 2014. Six of the seven Hardisty rail terminal service agreements have automatic one-year renewal provisions and will terminate only if written notice is given by either party within a specified time period before the end of the initial term or a renewal term. The seventh agreement will renew upon written agreement at least six months prior to the end of the initial term or the then current renewal term. 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 rail terminal unless due to our negligence.

Under the terminal services agreements we have entered into with customers of our Hardisty rail 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 rail terminal. If a customer loads fewer unit trains or barrels than its maximum 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.

San Antonio Rail Terminal

Our San Antonio rail terminal, completed in April 2010, is a unit train-capable destination terminal that transloads ethanol received by rail from Midwestern producers onto trucks to meet local ethanol demand in San Antonio and Austin, Texas. Our San Antonio rail terminal is located within five miles of San Antonio’s gasoline blending terminals and is the only ethanol rail terminal within a 20-mile radius. 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 transportation concerns, combined with the proximity of our San Antonio rail terminal to local demand markets, strategically positions our San Antonio rail terminal to benefit from anticipated changes in environmental and gasoline blending regulations that are expected to make the role of ethanol more pervasive in the market for transportation fuel.
 
The San Antonio rail terminal can transload up to 20,000 bpd, of ethanol with 20 railcar offloading positions and three truck loading positions. The facility receives inbound deliveries exclusively by rail on Union Pacific

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Railroad’s high speed line. We have entered into a terminal services agreement with a subsidiary of an investment grade company for our San Antonio rail terminal pursuant to which our customer pays us per gallon fees based on the amount of ethanol offloaded at the terminal. The San Antonio terminal services agreement was originally scheduled to expire in August 2015. On January 22, 2015, we entered into an amendment with our customer at our San Antonio rail terminal whereby the service agreement will automatically extend for two additional 18 month terms unless the customer provides written notice six months prior to the end of a term. The customer did not provide notice to terminate the agreement, and the term of the agreement now extends to February 2017. The current agreement entitles the customer to 100% of the terminal’s capacity, subject to our right to seek additional customers if minimum volume usage thresholds are not met. Our customer has consistently met its minimum utilization requirements since the inception of the agreement.
 
West Colton Rail Terminal
 
Our West Colton rail terminal, completed in November 2009, is a unit train-capable destination terminal that transloads ethanol received by rail from regional and other producers onto trucks to meet local ethanol demand in the greater San Bernardino and Riverside County-Inland Empire region of Southern California. Our West Colton rail terminal is located less than one mile from gasoline blending terminals that supply the greater San Bernardino and Riverside County-Inland Empire region and is the only ethanol rail terminal within a ten-mile radius. Additionally, like our San Antonio rail terminal, our West Colton rail terminal is strategically positioned to benefit from any increases in the utilization of ethanol in the market for transportation fuel.
 
The West Colton rail terminal can transload up to 13,000 bpd of ethanol with 20 railcar offloading positions and three truck loading positions. The facility receives inbound deliveries exclusively by rail from Union Pacific Railroad’s high speed line. After receipt at our West Colton rail terminal, ethanol is then transported to end users by truck. We have been operating under a terminal services agreement at West Colton with a subsidiary of an investment grade company since July 2009, which is terminable at any time by either party. Under this agreement, we receive a per gallon fee based on the amount of ethanol offloaded at the rail terminal. We are currently in the process of seeking permits to construct an approximately one-mile pipeline directly from our West Colton rail terminal to Kinder Morgan Inc.’s gasoline blending terminals, which, if approved and constructed, may result in additional long-term volume commitments and cash flows.
Fleet Services
 
We provide fleet services for a railcar fleet consisting of approximately 3,099 active railcars as of December 31, 2014, with an additional 650 expected to be available for service in the first half of 2015. We do not own any railcars. Affiliates of USD lease 3,096 of the railcars in our fleet from third parties, including the additional 650 railcars expected to be available for service in the first half of 2015. We directly lease 653 railcars from third parties. We have entered into master fleet services agreements with a number of our rail terminal customers for the use of the 653 railcars in our fleet that we lease directly. We have also entered into services agreements with affiliates of USD for the provision of fleet services with respect to the 3,096 railcars that they lease from third parties. These agreements are on a take-or-pay basis for periods ranging from five to nine years, with a weighted-average remaining life of 6.5 years for agreements dedicated to customers of our Hardisty rail terminal. In the aggregate, our master fleet services agreements have a weighted-average life of 5.2 years. Under our master fleet services agreements with our customers and the services agreements with affiliates of USD, we provide customers with railcar-specific fleet services associated with the transportation of crude oil, which may include, among other things, the provision of relevant administrative and billing services, the 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. We typically charge our customers, including affiliates of USD, monthly fees per railcar that include a component for railcar use (in the case of our directly-leased railcar fleet) and a component for fleet services. Our master fleet services agreements and the services agreements with affiliates of USD will expire unless notice to renew is provided by our customers, including affiliates of USD. Approximately 66% of our current railcar fleet is dedicated to customers of our terminals. The remaining 34% of the railcar fleet is dedicated to a customer of terminals belonging to subsidiaries previously sold by our predecessor. We believe our ability to provide access to railcars provides an incentive to customers that do not otherwise have access to high-quality railcars to secure terminalling capacity at our facilities. We expect that the longer terms typical of fleet services agreements will also incentivize our customers to extend their initial terminal services agreements with us.

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Approximately 70% of our railcars currently in service were constructed in 2013 and 2014. The average age of our fleet currently in service is approximately four 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, Trinity Industries and others. We believe that our relationships with these industry leaders enable us to obtain railcar market insight and to procure railcars on more advantageous terms, with shorter lead times than our competitors. Our current railcars are designed to a DOT-111 railcar standard and are built to carry between 28,000 to 31,800 gallons of bulk liquid volume. Nearly 98% of our railcar fleet is currently permitted to transport crude oil in the United States and Canada. The remaining 2% of our fleet is impacted by Railworthiness Directive, Notice NO. 1 , issued by the U.S. Department of Transportation ("DOT") on March 13, 2015. This directive prohibits any railcar equipped with certain McKenzie UNNR Valves to be loaded and offered for transportation. We are currently coordinating with the railcar suppliers and our customers to repair the affected railcars, the costs of which are the obligations of our railcar suppliers or our customers. Nearly 80% of our railcars are equipped with the most recent safety enhancements including thicker, more puncture-resistant tank shells, extra protective head shields and greater top fittings protection.
 
As of December 31, 2014, our railcar fleet consisted of a mix of 2,108 coiled and insulated ("C&I") railcars (inclusive of 650 C&I railcars which are currently in production and scheduled for delivery in the first half of 2015), and 1,641 non-coiled, non-insulated railcars. Our C&I railcars can reheat heavy viscous crude oil grades, reducing the need to blend these heavier crude grades with diluents. Additionally, we have the option to procure another 425 new C&I railcars scheduled for delivery in late 2015.

BENEFITS OF RAIL

The following benefits of rail have become a primary focus for producers, refiners, marketers and other energy-related market participants, and as such, have established, or have the potential to establish, rail as a preferred mode of transportation for crude oil as well as refined petroleum products, biofuels, natural gas liquids ("NGLs") and frac sand/proppant:

Access to areas without existing or easily accessible transportation infrastructure. Many of the emerging producing regions, such as the Western Canadian oil sands, have concentrated production in areas with either limited or virtually no existing cost-effective takeaway capacity. The extensive existing rail infrastructure network provides efficient takeaway capacity to these producing regions and 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 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 producers and shippers 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, as refinery output grows, rail provides refiners access to the most attractive refined petroleum products and NGL markets.

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 are typically contracted on a spot basis). 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 significant operating cost advantages, particularly in situations where either (i) the amount of diluent required for the transportation of crude oil by pipeline is high,

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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.

OUR GROWTH OPPORTUNITIES — HARDISTY PHASE II AND PHASE III EXPANSIONS
 
Our sponsor currently owns the right to construct and develop additional infrastructure at the Hardisty rail terminal, which could expand the number of unit trains that can be loaded from two unit trains to up to five unit trains per day. We refer to these expansion projects as Hardisty Phase II and Hardisty Phase III. USD is currently in the process of contracting, designing, engineering and permitting Hardisty Phase II, which would expand the capacity for handling and transporting crude oil by two unit trains per day. We expect the additional capacity will be contracted under multi-year take-or-pay agreements similar to what we currently have in place at our Hardisty rail terminal. Subject to receiving required regulatory approvals and obtaining required permits on a timely basis, successful contracting of the expanded capacity and the absence of unanticipated delays in construction, USD currently expects that Hardisty Phase II will commence operations in the first half of 2016. Hardisty Phase III would expand capacity by one unit train per day and would target the loading of bitumen with very limited amounts of diluent through the use of C&I railcars. Because of the high viscosity of the bitumen product, it cannot typically be transported by pipeline without further blending with diluent. Hardisty Phase III will require additional infrastructure to be designed, engineered, permitted and constructed. Subject to receiving required regulatory approvals and obtaining required permits on a timely basis, successful contracting of the expanded capacity and the absence of unanticipated delays in construction, we currently anticipate that Hardisty Phase III will commence operations during 2017. In connection with our IPO, we entered into an omnibus agreement with USD and USD Group LLC, pursuant to which USD Group has granted to us a right of first offer on Hardisty Phase II and Hardisty Phase III for a period of seven years after the closing of the IPO. Additional information about the omnibus agreement and the right of first offer are included in this Annual Report under Item 13. Certain Relationships and Related Transactions, and Director Independence.
 
We cannot assure you that USD will be able to develop or construct, or that we will be able to acquire, any other midstream infrastructure projects, including the Hardisty Phase II or Hardisty Phase III projects. Among other things, the ability of USD to develop the Hardisty Phase II and Hardisty Phase III projects, 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 USD Group LLC are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer, including the Hardisty Phase II and Hardisty Phase III projects. 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 the Hardisty Phase II and Hardisty Phase III 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. If we are unable to acquire the Hardisty Phase II or Hardisty Phase III projects from USD Group LLC, these expansions may compete directly with our Hardisty rail 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. 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 the Hardisty Phase II and Hardisty Phase III projects.

COMPETITION 

The crude oil and hydrocarbon logistics business is highly competitive. The ability to secure additional agreements for rail terminalling and railcar fleet services is primarily based on the reputation, efficiency, flexibility, location, market economics and reliability of the services provided and pricing for those services.
 
Our Hardisty rail terminal faces competition from other logistics services providers, such as pipelines and other rail terminalling service providers. If our customers choose to ship crude oil via alternative means, we may only receive the minimum monthly commitment fees at our Hardisty rail terminal. Our San Antonio and West Colton rail terminals face 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, versatility or services provided. Both facilities are served by the Union Pacific ("UP") Railroad. In the Southern California market, we compete directly

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with ethanol facilities in the Fontana, Carson and San Diego areas served by Burlington Northern Santa Fe ("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 on terminalling throughput fees alone. In the San Antonio market, we also compete with a facility which is served by BNSF, although our facility which is served by UP is closer to the San Antonio metro area which typically results in advantaged trucking rates for certain end-user customers.
 
Our railcar fleet services face competition from other providers of railcars in excess of the railcars we have currently contracted under our master fleet services agreements. This competition may limit our ability to increase the number of railcars under contract, and thus, limit our ability to increase our revenues. Furthermore, we face competition from other parties interested in procuring railcars equipped to carry crude oil. However, we believe our relationships with leaders in the railcar supply industry such as CIT Rail, Union Tank Car Company and Trinity Industries, enable us to continue procuring railcars on more advantageous terms, with shorter lead times than our competitors.
 
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, independent strategy, our reputation and industry relationships, and the quality, 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 crude oil 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 rail terminals is affected by the level of supply and demand for crude oil, refined products and biofuels as well as 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. Decreased demand during the winter months can lower gasoline prices. 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 commit our customers to pay a base monthly fee per railcar under contract. Furthermore, because there are multiple end markets for the crude oil and biofuels we handle at our rail terminals, the effect of seasonality otherwise attributable to one particular end market is mitigated.

 REGULATION

General
 
Our operations are subject to complex and frequently-changing federal, state, provincial and local laws and regulations regarding the protection of health 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 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 rail terminalling and logistics needs. As a result, we expect to increase our market share in relation to customer-owned operations or smaller operators that lack an established track record of safety.
 
Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. We believe our facilities are in substantial compliance with applicable environmental 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 rail 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 laws or regulations.

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Air Emissions
 
Our operations are subject to and affected by the 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 rail terminals when regulations change, or we add new equipment, or 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 GHG, emissions as well 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 EPA has indicated that it intends to regulate carbon dioxide emissions. 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. We are uncertain what our customers’ responses to these emerging issues will be. Those responses could reduce throughput at our rail terminals, and impact our cash flows and ability to make distributions or satisfy debt obligations.

Climate Change
 
United States. Following its December 2009 “endangerment finding” that GHG emissions pose a threat to public health and welfare, the 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 ("PSD") pre-construction permits and Title V operating permits for GHG emissions from certain large stationary sources. 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. We believe we are in substantial compliance with all GHG emissions permitting and reporting requirements applicable to our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low-carbon technologies. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil, which could thereby reduce demand for our services. Finally, it should be noted 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, droughts and floods and 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 operations.

Canada. In response to recent studies suggesting that emissions of CO2, methane and certain other gases may be contributing to warming of the Earth’s atmosphere, many nations, including Canada, have agreed to limit emissions of these GHGs pursuant to the 1997 United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” The Kyoto Protocol required Canada to reduce its emissions of GHG to 6% below 1990 levels by 2012. However, by 2009, emissions in Canada were 17% higher than 1990 levels. In December 2011, Canada withdrew from the Kyoto Protocol, but signed the “Durban Platform” committing it to a legally binding treaty to reduce GHG emissions, the terms of which are to be defined at the Paris climate conference in 2015 and are to become effective in 2020. The Canadian Department of Environment ("Environment Canada") continues to promote the domestic GHG initiatives implemented while Canada was signatory to the Kyoto Protocol. With regard to the oil and gas industry, it is unclear at this time what direction the government 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

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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.

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 ("CERCLA" or "Superfund") 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 being 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 ("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. The 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.

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Water
 
The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act ("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 Oil Pollution Act of 1990 ("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 and Virginia, and more recently in 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 ("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 on September 9, 2014. In August 2013, the FRA and Pipeline and Hazardous Materials Safety Administration ("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 November 2013, the rail industry called on the PHMSA to require that legacy railcars used to transport flammable liquids, including crude oil, be retrofitted with enhanced safety features, or be phased-out. In January 2014, the DOT, including the PHMSA and FRA, met with oil and rail industry leaders to develop strategies to prevent train derailments and reduce the risk of fire and explosions. As a result of those meetings, the DOT and transportation industry agreed in February 2014 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.

On February 25, 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. On April 23, 2014, the Canadian Minister of Transport, which oversees Transport Canada, announced a series of directives and other actions to address the

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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; thereafter, retrofitted DOT-111 railcars will be permitted to be used only with respect to certain packing groups until May 2025. We currently provide railcar services for 413 railcars that are subject to this directive, but which have leases that will expire before May 2017, and 383 railcars that will still be under contract and will be required to be retrofitted pursuant to this directive. We do not own any of the railcars in our railcar fleet and are not directly responsible for costs associated with the retrofitting of DOT-111 railcars. However, costs associated with the retrofitting of railcars would increase the incremental monthly cost of the applicable railcar lease, which cost we would seek to pass through to our customers and could affect demand for our services. We intend to work with our railcar suppliers on modification scheduling in an attempt to avoid major disruptions. Transport Canada also identified key routes and revised operating practices put in place for the transportation of crude oil on those routes.

On May 7, 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 on May 7, 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. On July 2, 2014, Transport Canada adopted the CPC-1232 technical standards as the minimum safety threshold for railcars transporting dangerous goods after May 2017. Transport Canada also proposed a new class of railcar (TC-140) specifically developed for the transport of flammable liquids in Canada, as well as a retrofit schedule for legacy DOT-111 and CPC-1232 railcars. The proposal was open for comment until September 1, 2014. The Canadian government is reviewing these comments and will issue final regulations for the specifications of these railcars. On July 23, 2014, the DOT issued a Notice of Proposed Rulemaking and a companion Advanced Notice of Proposed Rulemaking addressing liquid flammable railcar requirements. This proposed rulemaking also addressed areas such as train speeds and oil testing, and other important issues such as emergency and spill response along the routes for flammable liquid unit trains. The newly proposed tank car standards would apply to railcars constructed after October 1, 2015 that are used to transport flammable liquids. The DOT is expected to release the final regulations in May of 2015. We expect Canada to quickly move to harmonize these regulations.

In March 2015, Transport Canada released regulatory proposals under development that address tank cars used to transport flammable liquids. Transport Canada has changed its formerly designated TC-140 tank car to TC-117. This new designation aligns with the DOT’s designation of its proposed new railcar for transporting liquid flammables, the DOT-117. Additionally, in the Transport Canada proposal, while still using the May 1, 2017, deadline for removing or retrofitting the older TC-111 railcars from crude oil service, they also proposed extending the deadline for those same cars used in ethanol service until May 1, 2020. Lastly, in their proposal, they recommended that a risk based approach for flammable liquids transportation be used and that the use of electronically controlled pneumatic braking systems be a part of that risk analysis. Once the United States adopts its new standards, we expect that Transport Canada will move quickly to implement its regulations in harmony with the United States.

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 may be required due to these new regulations. Nearly 70% of our fleet was manufactured in 2013 and 2014 and has been constructed to the CPC-1232 standard. 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 may be able to pass some of these costs on to our customers, there may 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 proposals, we do not anticipate a material impact to our ability to transport crude oil under our existing contracts. If the final rulings 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.  

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

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compliance costs and decreasing demand for our services, which could adversely affect our financial position and cash flows.

Employee Safety  

We are subject to the requirements of the U.S. federal Occupational Safety and Health Act ("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 ("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, OSH in Canada and comparable 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 ("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 56 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 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 logistics 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 http://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 ("the Exchange Act"), as soon as reasonably practicable after we electronically file such material with the SEC. 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. Each of these risk factors could have an adverse affect on our business, operating results, cash flows and financial condition, as well as the value of an investment in our common units.
Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common, Class A, subordinated and general partner units.
 
In order to pay the minimum quarterly distribution of $0.2875 per unit per quarter, or $1.15 per unit on an annualized basis, we require available cash of approximately $6.1 million per quarter, or $24.6 million per year, based on the number of common units, Class A units, subordinated units and general partner units outstanding at December 31, 2014. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. 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;
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 we 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 or otherwise;
prevailing economic and market conditions;
the level of our operating, maintenance and general and administrative costs;
regulatory action affecting railcar design or the transportation of crude oil by rail; 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;
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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We serve customers who are involved in drilling for, producing and transporting crude oil and other liquid hydrocarbons. Adverse developments affecting the fossil fuel industry or drilling activity, including declines in 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 rail terminals.

Our business, including our ability to grow our business through the contracting and development of new rail terminals, as well as our ability to secure renewals or extensions of agreements with customers at our existing rail terminals, depends on the continued development and production of crude oil and other liquid hydrocarbons from 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 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 sustained reduction in the prices of crude oil and other commodities would have a material adverse effect on our business. 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;
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 shutdowns;
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;
fluctuations in demand from electric power generators and industrial customers; and
the anticipated future prices of oil and other commodities.

During the fourth quarter of 2014 and continuing into 2015, the prices of crude oil and related products have dropped substantially. In addition, our Hardisty rail terminal is located in a region that is generally considered to have relatively high production costs. If crude oil prices do not recover, or take longer to recover than anticipated, exploration and production companies in the region may reduce capital spending on maintaining or growing production, which would likely have a material adverse impact on our business and results of operations. 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 or renegotiate their agreements with us for various reasons.

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 crude oil terminalling services at our Hardisty rail terminal. Substantially all of the capacity at our Hardisty rail terminal is contracted under multi-year, take-or-pay terminal services agreements. A 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 may be 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. 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, one customer has the right, but not the obligation, to exclusively use all of our capacity at our San Antonio rail terminal under a three-year contract that commenced in 2012, and was also the sole customer under contract at our West Colton rail terminal. The West Colton agreement is terminable at any time. If we were unable to renew our contracts with one or more of these customers, including customers at our Hardisty rail terminal, on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all.

The amount of cash we have available for distribution to holders of our common and subordinated 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 make cash distributions during periods when we record net earnings for financial accounting purposes.
 
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, which is subject to regulations governing railcar design and manufacture. As a result of hydraulic fracturing and other improvements in extraction technologies, there has been a substantial increase in the volume of crude oil and liquid hydrocarbons produced and transported in North America, and a geographic shift in that production versus historical production. The increase in volume and shift in geography has resulted in a growing percentage of crude oil being transported by rail. High-profile accidents involving crude-oil-carrying trains in Quebec, North Dakota and Virginia, and more recently in West Virginia and Illinois, have raised concerns about the environmental and safety risks associated with crude oil transport by rail and the associated risks arising from railcar design.
 
The U.S. DOT and Transport Canada have announced a series of directives and other actions to address rail safety concerns. Among the directives from Transport Canada is a requirement that 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 with none in use after May 2025 and non-jacketed CPC-1232 railcars to be phased out by July 1, 2023. We currently provide fleet services for 413 railcars that are subject to this directive, but which have leases that will expire before May 2017, and 383 railcars that will still be under contract and will be required to be retrofitted pursuant to this directive. We do not own any of the railcars in our railcar fleet and are not directly responsible for costs associated with the retrofitting of DOT-111 railcars. However, costs associated with the retrofitting of railcars would increase the incremental monthly cost of the applicable railcar lease, which cost would get passed through to our customers and could affect demand for our services. We intend to work with our railcar suppliers on modification scheduling in an attempt to avoid major disruptions. Transport Canada also identified key routes and revised operating practices put in place for the transportation of crude oil on those routes.

Nearly 70% of our fleet was manufactured in 2013 and 2014 and has been constructed to the CPC-1232 technical standards adopted by Transport Canada as the minimum safety threshold for railcars transporting dangerous goods after May 2017. In February 2015, DOT submitted its final railcar regulations to the Office of Management and Budget for review. A final ruling is expected later this year. If the 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

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we may be able to pass some of these costs on to our customers, there may be additional costs that we cannot pass on to them. We continue to monitor the railcar regulatory landscape and remain in close contact with railcar suppliers and other industry stakeholders to stay informed of railcar regulation rulemaking developments. Our ability to transport crude oil under our existing contracts could be affected if the final rulings result in more stringent design requirements and compressed compliance timelines than currently published. If the final rulings 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.
 
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. Moreover, any disruptions in the operations of railroads, including those due to shortages of railcars, weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts or bottlenecks, could adversely impact our customers’ ability to move their product and, as a result, could affect our business. 

Because we have a limited operating history, you may have difficulty evaluating our ability to pay cash distributions to our unitholders, or our ability to be successful in implementing our business strategy.
 
We are dependent on our Hardisty rail terminal as our primary source of cash flow. As a newly constructed rail terminal, the operating performance of the Hardisty rail terminal over the short term and long term is not yet proven. We may encounter risks and difficulties frequently experienced by companies whose performance is dependent upon newly constructed facilities, such as the rail terminal not functioning as expected, higher than expected operating costs, breakdown or failures of equipment and operational errors.
 
Because of our limited operating history and performance record at the Hardisty rail terminal, it may be difficult for you to evaluate our business and results of operations to date and to assess our future prospects. Further, our historical financial statements present a period of limited operations, and therefore do not provide a meaningful basis for you to evaluate our operations or our ability to achieve our business strategy. We may be less successful in achieving a consistent operating level at the Hardisty rail terminal capable of generating cash flows from our operations sufficient to regularly pay a cash distribution, or to pay any cash distribution to our unitholders than a company whose major facilities have had longer operating histories. Finally, we may be less equipped to identify and address operating risks and hazards in the conduct of our business at the Hardisty rail terminal than those companies whose major facilities have had longer operating histories.

Our management has limited experience in managing our business as a U.S. publicly traded partnership.
Our executive management team and internal accounting staff have limited experience in managing our business and reporting as a U.S. publicly traded partnership. As a result, we may not be able to anticipate or respond to material changes or other events in our business as effectively as if our executive management team and accounting staff had such experience. Furthermore, growth projects may place significant strain on our management resources, thereby limiting our ability to execute our business strategy.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

Our current rail terminals are located in Texas, California and Alberta, Canada. We generate the vast majority of our operating cash flow in connection with providing crude oil terminalling services at our Hardisty rail terminal. 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 Hardisty rail terminal, including those due to catastrophic events, 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, oil sands production in Canada may be particularly susceptible to decline as a result of

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long-term declines in the price of crude oil, which could materially impact the results of operations at our Hardisty rail terminal and the ability of USD Group LLC to contract for and complete the planned expansions of the Hardisty rail terminal on its anticipated schedule, if at all.

Changes in the provincial royalty rates and drilling incentive programs in Canada could decrease the oil and gas exploration and pipeline activities in Canada, which could adversely affect the demand for our rail 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 rail terminalling services.

The dangers inherent in our operations could cause disruptions and could 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 rail terminalling operations are conducted at the Hardisty rail terminal.
 
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 rail 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 most of our cash flow is generated from our rail terminalling operations conducted at our Hardisty rail terminal, any sustained disruption at the Hardisty rail terminal or the Gibson storage terminal, which is the source of all of the crude oil handled by our Hardisty rail 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.
 
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 competitors include, but are not limited to, crude oil pipelines, ocean going tankers, major integrated oil companies, independent gatherers, trucking companies and crude oil marketers of widely varying sizes, financial resources and experience. We compete against these companies on the basis of many factors, including geographic proximity to production areas, market access, rates, terms of service, connection costs and other factors. Some of our competitors have capital resources many times greater than ours.
 
A significant driver of competition in some of the markets where we operate is the rapid development of new midstream infrastructure capacity driven by the combination of (i) significant increases in oil and gas production and development in the applicable 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. 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. In addition, as an established player in some markets, we also face competition from potential new entrants to the market. 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 ability to make quarterly distributions to our unitholders.

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Any reduction in our or our customers’ capability to utilize third-party pipelines, railroads or trucks that interconnect with our rail terminals or to continue utilizing them at current costs could cause a reduction of volumes transported through our rail terminals.
 
We and the customers of our rail terminals are dependent upon access to third-party 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 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, in the case or railroads, could result in reduced volumes transported through our rail terminals. In particular, we entered into a facilities connection agreement with Gibson whereby Gibson would construct a pipeline to provide our Hardisty rail terminal with exclusive pipeline access to Gibson’s storage terminal, which is the source of all of the crude oil handled by our Hardisty rail terminal. Any disruption at Gibson’s storage terminal or at this newly-constructed pipeline could have a material adverse effect on our business, financial condition, results of operations and cash flows. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which could reduce volumes transported through our rail terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such increases in cost, interruptions, or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.
 
We do not own some of the land on which our rail terminals are located, which could disrupt our operations.
 
We do not own the land on which our West Colton and San Antonio rail terminals are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate at those facilities. We sometimes obtain the rights to land owned by railroads for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.

A shortage in rail locomotives or railroad crews or increases in the price of diesel fuel may adversely affect our results of operations.
 
Transporters of hydrocarbons by rail compete with other parties, such as coal, grain and corn, which ship their product by rail. The increased demand for transportation of crude or other products by rail has recently 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 either as a result of a shortage of locomotives or railroad crews or increased diesel fuel costs could curtail demand for shipment of hydrocarbons by rail which would have an adverse effect on our results of operations and cash flows.
 
The fees charged to customers under our agreements with them for the transportation of crude oil may not escalate sufficiently 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 crude oil terminalling services at our Hardisty rail terminal. Substantially all of the capacity at our Hardisty rail terminal is contracted under multi-year, take-or-pay terminal services agreements, which are subject to inflation-based rate escalators. Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to such inflation-based escalators. 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 include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export

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restrictions, strikes, lockouts, fires, storms, floods, acts of God, 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 the escalation of fees is insufficient to cover increased costs, or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.
 
Our right of first offer to acquire certain of USD’s existing assets and projects and certain assets or businesses that it may develop, construct or acquire in the future is subject to risks and uncertainty, and ultimately we may not acquire any of those assets or businesses.
 
Our omnibus agreement provides us with a right of first offer for a period of seven years from October 15, 2014 on certain of USD’s existing assets and projects as well as any additional midstream infrastructure assets or businesses that it may develop, construct or acquire in the future, subject to certain exceptions. 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 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 the Hardisty Phase II and Hardisty Phase III 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 Item 13. Certain Relationships and Related Transactions, and Director Independence for additional information regarding our omnibus agreement.
 
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 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.

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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.

We may be unsuccessful in integrating any future acquisitions with our existing operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
 
From time to time, we evaluate and expect to acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.
 
Growing our business by constructing new rail terminals subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.
 
One of the ways we intend to grow our business is through the construction of new rail terminals. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new rail terminal, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct rail terminals to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to build new rail terminals, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new rail terminals may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition.
 
USD and its controlled affiliates, including us, are subject to a noncompete agreement that may limit our growth opportunities.
 
USD and certain of its controlled affiliates, including us, are subject to a noncompete agreement until December 2016 with respect to rail terminals we sold in 2012 in Carr, Colorado; Cotulla, Texas; Van Hook, North Dakota; Bakersfield, California; and St. James Parish, Louisiana. The noncompete agreement prohibits us from owning, managing, operating or engaging in business activities related to terminalling services within a 200-mile radius of each of these facilities with respect to grades of crude oil and condensate historically handled by the facilities, or a 100-mile radius with respect to all other grades of crude oil or condensate. As a result of this noncompete agreement, our future growth may be limited during the term of the noncompete agreement.

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, employment, labor, immigration, minimum wages and overtime pay, health care and benefits, working conditions, public accessibility and other requirements. These laws and regulations are enforced by federal agencies including the EPA, the DOT, PHMSA, the FRA, the Federal Motor Carrier Safety Administration ("FMCSA"),

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OSHA, and state and Canadian agencies such as the Texas Commission on Environmental Quality, the Railroad Commission of Texas, the California Environmental Protection Agency ("Cal/EPA"), the California Public Utilities Commission ("CPUC"), 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, 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. 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 terminals or discover historical releases that were previously unidentified or not assessed. Although our inspection and testing programs are designed 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 regulation is becoming more stringent, and new environmental laws and regulations are continuously being enacted or proposed and interpretations of existing requirements change from time to time. While it is impractical to predict the impact that future environmental, health and safety requirements or changed interpretations of existing requirements may have, such future activity may result in material expenditures to ensure our continued compliance. Such future activity could also adversely affect our ability to expand production, result in damaging publicity about us, or reduce demand for our products and services.

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 impacts or potential impacts 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 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.

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The implementation of derivatives legislation by the United States Congress 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 United States Congress in 2010 adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act"), which, among other things, established federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. While many regulations have been promulgated and are already in effect, the rule making and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the regulations on our business. The legislation and any new regulations could significantly 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 and our results of operations.
 
Our contracts subject us to renewal risks.
 
We provide crude oil and other liquid hydrocarbon rail terminalling services under contracts with terms of various durations and renewal. Each of the seven terminal services agreements with our Hardisty rail terminal customers has an initial contract term of five years. The initial terms of six of these agreements commenced between June 30, 2014 and August 1, 2014, and the initial term of a seventh agreement commenced on October 1, 2014. Our sole customer contract for our San Antonio rail terminal has a current term expiring in February 2017 with an automatic renewal for one additional 18 month term unless notice is provided by our customer. Our sole customer contract for our West Colton rail terminal is terminable at any time.
 
As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and 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 have decreased significantly. 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 arrangements. 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, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially and adversely affected.
 
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 rail terminalling services, including:
damage to railroads and rail 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;
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 losses 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

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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 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. 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.

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 or acts of war 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 or its 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 attacks than other targets in the United States. 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. Disruption or significant increases 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.
 
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. 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 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 growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.
 
We continuously consider and enter into discussions regarding potential acquisitions or growth capital expenditures. 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.

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Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially, while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally, and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have raised interest rates, enacted tighter lending standards, refused to refinance existing debt at all at maturity or on terms similar to existing debt outstanding and reduced and in some cases, ceased to provide funding to borrowers. These factors may limit our ability to execute our growth strategy.
 
In addition, we are experiencing increased competition for the types of assets we contemplate purchasing. Weak economic conditions and competition for asset purchases could limit our ability to fully execute our growth strategy.
 
While Energy Capital Partners has indicated an intention to invest over an additional $1.0 billion of equity capital in USD, subject to market and other conditions, it has not made a commitment to provide any direct or indirect financial assistance to us. Furthermore, Energy Capital Partners must approve any issuances of additional equity by us, which 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.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
We have the ability to incur additional debt, including under our senior secured credit facilities that we entered into in connection with the IPO. Our future level of debt 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 future 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 any future 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.
 
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 entered into a senior secured credit agreement comprised of a $200.0 million revolving credit facility and a $100.0 million term loan in connection with the closing of the IPO. We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations 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;

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make certain investments and acquisitions;
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.
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.
 
Increased regulation of hydraulic fracturing could result in reductions or delays in oil production by our customers, which could adversely impact our revenues
 
A portion of our customers’ oil production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is an essential and common practice in the oil industry used to stimulate production of oil from dense subsurface rock formations in the United States and Canada. The process is typically regulated by state and provincial oil and natural gas commissions.
 
Hydraulic fracturing has been subject to increased scrutiny due to public concerns that it could result in contamination of drinking water supplies, and there have been a variety of legislative and regulatory proposals to prohibit, restrict or more closely regulate various forms of hydraulic fracturing.
 
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to increased operating costs in the production of oil or could make it more difficult to perform hydraulic fracturing, either of which could have an adverse effect on our operations. The adoption of any federal, state, provincial or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil wells, increasing compliance costs and decreasing demand for our terminalling and other services, which could adversely affect our financial position, results of operations and cash flows.
 
We are subject to stringent environmental 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 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 railcars and rail terminals, and the imposition of substantial liabilities 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, Environment 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,

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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 rail 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.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the oil services we provide.
 
In response to recent studies suggesting that emissions of carbon dioxide, methane and certain other gases may be contributing to warming of the Earth’s atmosphere, Canada agreed to limit emissions of these GHGs pursuant to the 1997 United Nations Framework Convention on Climate Change, also known as the Kyoto Protocol. In December 2011, Canada withdrew from the Kyoto Protocol, but signed the Durban Platform committing it to a legally binding treaty to reduce GHG emissions, the terms of which are to be defined at the Paris climate conference in 2015 and are to become effective in 2020.
 
While not a signatory to the Kyoto Protocol or the Durban Platform, 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, 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. In California, the AB 32 program created a statewide cap on GHG emissions and requires that the state return to 1990 emission levels by 2020. AB 32 focuses on using market mechanisms, such as a cap-and-trade program and a low-carbon fuel standard (LCFS), to achieve emission reduction targets. 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 measures such as the LCFS are successful in reaching hydrocarbon fuel usage, they could have an indirect effect on our business.
 
Independent of Congress, the EPA is beginning to adopt regulations controlling 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 and, in November 2010, expanded this existing GHG emissions reporting rule for petroleum facilities, requiring reporting of GHG emissions by regulated petroleum facilities to the EPA beginning in 2012 and annually thereafter. We monitor and report our GHG emissions. However, operational or regulatory changes 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. Several of the EPA’s GHG rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions 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 and could adversely affect demand for the crude oil and other liquid hydrocarbons we handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict

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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 rail 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.
 
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.
 
If we fail to develop or 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.
 
Prior to our IPO, we were not required to file reports with the SEC. Upon the completion of our IPO, we became subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, 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 attest to, the effectiveness of our internal controls over financial reporting.
 
Although we are required to disclose changes made in our internal control and procedures on a quarterly basis, we are not required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until our annual report for the fiscal year ending December 31, 2015.
 
Any failure to develop, implement or 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 an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.
 
For as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (JOBS Act), we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive

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compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700.0 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.
 
In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
 
To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.
 
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 majority 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 could result in an increase in our financing expenses and could materially affect our financial results under 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, long-term debt 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.

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 North American Free Trade 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.


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Risks Inherent in an Investment in Us

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 54.2% limited partner interest and indirectly owns and controls our general partner, which owns a 2.0% 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 partnership agreement nor any other agreement requires USD to pursue a business strategy that favors us, and the directors and officers of USD have a fiduciary duty to make these decisions in the best interests of the shareholders 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 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, the amount of adjusted operating surplus generated in any given period, the conversion ratio of vested Class A units and the ability of the subordinated units to convert into common units;
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, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions, to affect the conversion ratio of Class A units to common units or to satisfy the conditions required to convert subordinated units to common units;
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 on our subordinated units or 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;

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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.
 
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.
 
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, the incurrence of debt by us, 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 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

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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.
 
At any time following the fifth anniversary of the date of Energy Capital Partners’ investment in USD, 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 (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.
 
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.
 
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. 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

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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 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 and subordinated 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;
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.

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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 such 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.
 
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 our 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 reduces the amount of distributable cash flow to unitholders. For the twelve months ending December 31, 2015, we estimate that these expenses will be approximately $2.5 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 Item 13. Certain Relationships and Related Transactions, and Director Independence 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, 2014, our general partner and its affiliates own 55.2% 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 under our directed unit program). Also, if our general partner is removed without cause during the time any subordinated units are outstanding and the subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our general partner

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under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Furthermore, all of the unvested Class A units will immediately vest and convert into common units based on the maximum conversion factor that could have applied to such Class A units. This conversion would adversely affect the common units by prematurely eliminating the liquidation preference of common units over the Class A units, which would have otherwise continued while certain conditions remained unsatisfied.
 
“Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing us will most likely result in the automatic conversion to common units of all remaining outstanding subordinated units.
 
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.
 
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.

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;
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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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.
 
USD Group LLC may sell 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 1,093,545 common units and 10,463,545 subordinated units at December 31, 2014. All of the subordinated units will convert into common units on a one-for-one basis in separate, sequential tranches, with each tranche comprising 20.0% of the subordinated units outstanding. A separate tranche will convert on each business day occurring no earlier than January 1, 2016 (but not more than once in any twelve-month period), assuming the conditions for conversion are satisfied. Additionally, we have agreed to provide USD Group LLC with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units.
 
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.
 
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 our 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 assets and businesses 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 develop Hardisty Phase II and Hardisty Phase III at our Hardisty rail terminal. USD Group LLC currently anticipates that Hardisty Phase II will commence operations in the first half of 2016, and Hardisty Phase III will commence operations during 2017. If we are unable to acquire these facilities from USD Group LLC, these expansions may compete directly with our Hardisty rail 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.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.
 
In some instances, our general partner may cause us to borrow funds under our revolving credit facility, from USD or otherwise from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to satisfy the conditions required to convert subordinated units into common units.

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Our general partner has a limited call right that it may exercise at any time it or its affiliates own more than 80.0% of the outstanding limited partner interests and that may require you to sell your common units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80.0% of the then issued and outstanding common units, our general partner has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner and its affiliates own approximately 10.7% of our common units (excluding any common units held by our officers, directors, employees and certain other persons affiliated with us) and 55.9% of our common units assuming the conversion of all subordinated units into common units.
 
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.

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 credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our 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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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 when there are no subordinated units outstanding and 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 2.0% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based 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 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.

We incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to the IPO. For example, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that further increase our costs, including requirements to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting.

The price of our common units may fluctuate significantly, and unitholders 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:

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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.”
Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service ("IRS") were to treat us as a corporation for 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 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 federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, 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 federal income tax purposes, there would be 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.

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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. Because of widespread state budget deficits and other reasons, several states 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 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. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for federal income tax purposes. Any modification to the 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 federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.
 
Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
 
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 it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it 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.
 
If the IRS contests the 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 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.
 
We are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of the income from our railcar fleet services business. If we do not obtain a favorable ruling from IRS, we will be required to continue to conduct this business in a subsidiary that is treated as a corporation for U.S. federal income tax purposes and is subject to corporate-level income taxes.
 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. In an attempt to ensure that 90% or more of our gross income in each tax year is qualifying income, we conduct a portion of our business,

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relating to railcar fleet services, in a subsidiary that is treated as a corporation for U.S. federal income tax purposes. We are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of the income from this business. If the IRS is unwilling or unable to provide a favorable ruling with respect to the income from our railcar fleet services business, we will continue to be subject to corporate-level tax on the revenues generated by this business. Conversely, if the IRS does provide a favorable ruling, we may choose to conduct our future railcar fleet services business in a tax pass-through entity. Such restructuring may result in a significant, one-time tax liability and other costs, which may reduce our cash available for distribution.
 
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 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 items, including depreciation recapture. 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.
 
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 (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 federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. 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 federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or 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 federal income tax purposes 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 IRS may challenge this treatment, 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 for federal income tax purposes 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 use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations

42




were issued, we may 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 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 and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. 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. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
  
The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has provided a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership

43




technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
 
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local 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 will likely be required to file state and local 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 and Texas. 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 and local tax returns.

Item 2. Properties
A description of our properties is included in Item 1. Business, which is incorporated herein by reference.

Our Hardisty rail terminal is located on land we own and our West Colton and San Antonio rail terminals are located on land owned by others and are operated by us under perpetual easements and rights-of-way, licenses, leases or permits that have been granted by private land owners, public authorities, railways or public utilities.
We have satisfactory title and other rights to all of the real estate assets that were contributed to us at the closing of our IPO. Under the contribution agreement, our sponsor agreed to indemnify us for any materially adverse title defects as of October 15, 2014, the closing date of our IPO. In addition, under the omnibus agreement, our sponsor has agreed to indemnify us for any materially adverse title defects and any failures to obtain certain consents and permits necessary to conduct our business, in each case, that are identified prior to the fifth anniversary of the closing of the IPO.
Obligations under our senior secured credit facility are secured by a first priority lien on our assets and those of our restricted subsidiaries, 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 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 our Predecessor or 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 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 our omnibus agreement, USD has agreed to indemnify us for certain environmental and other liabilities attributable to the ownership or operation of the assets contributed to us in connection with the IPO that occurred prior to the closing of the IPO.



44




Item 4. Mine Safety Disclosures
Not Applicable.


45




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, the principal market for our common units, under the symbol "USDP". On October 15, 2014, we completed the initial public offering of 9,120,000 common units to the public at a price of $17.00 per unit. Prior to our IPO, there was no public market for our common units. The following table reflects intraday high and low sales prices per common unit and cash distributions declared to unitholders for each quarter starting October 8, 2014, the date on which our common units began trading on the NYSE.
 
 
Fourth Quarter
2014
 
 
High
 
$
17.48

Low
 
$
12.10

Quarterly Cash Distribution Per Unit (1)
 
$
0.24375

 
(1) 
Represents cash distribution attributable to the quarter and declared and paid within 60 days following the end of such quarter. The quarterly cash distribution per unit for the fourth quarter of 2014 was prorated for the period from October 15, 2014 through December 31, 2014.
On March 24, 2015, the last reported sales price of our common units on the NYSE was $13.04. At March 24, 2015, there were approximately 1,362 common unitholders, of which there was 1 registered common unitholder of record. An established public trading market does not exist for our Class A units, subordinated units, or our general partner units. Our Class A units are held by senior management of USD. All of our subordinated units are held by USD Group LLC, while all of our general partner units are held by USD Partners GP LLC.
Under our current cash distribution policy, we intend to make minimum quarterly distributions to the holders of our common units, Class A units, subordinated units and general partner units of $0.2875 per unit, or $1.15 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner and its affiliates. Our current cash distribution policy is also subject to certain restrictions, as well as the discretion of our general partner in determining the amount of our available cash each quarter. These restrictions include restrictions under our senior secured credit agreement, our general partner's discretion to establish reserves and to take other actions provided by our limited partnership agreement, and the performance of our subsidiaries. For further information about distributions and about these and other limitations and risks related to distributions, please read Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Distributions.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Please see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Securities Authorized for Issuance Under Equity Compensation Plans for information regarding our equity compensation plans as of December 31, 2014.

UNREGISTERED SALES OF EQUITY SECURITIES
 
None not previously reported on a current report on Form 8-K.
 
ISSUER PURCHASES OF EQUITY SECURITIES
 
None.



46




Item 6. Selected Financial Data
The following table sets forth, for the periods and at the dates indicated, our summary historical financial data of USD Partners LP and our Predecessor. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
For the Year Ended December 31,
 
2014
 
2013
 
2012
 
(in thousands, except per unit amounts and bpd)
Income Statement Data:
 
 
 
 
 
Operating revenues
$
36,098

 
$
26,301

 
$
24,875

Operating costs
35,451

 
24,832

 
21,744

Operating income
647

 
1,469

 
3,131

Interest expense
4,825

 
3,241

 
2,050

Gain associated with derivative instruments
(1,536
)
 

 

Foreign currency transaction loss
4,850

 
39

 

Provision for income taxes
186

 
30

 
26

Income (loss) from continuing operations
(7,678
)
 
(1,841
)
 
1,055

Discontinued operations:
 
 
 
 
 
Income from discontinued operations

 
948

 
65,204

Gain on sale from discontinued operations

 
7,295

 
394,318

Net income (loss)
$
(7,678
)
 
$
6,402

 
$
460,577

Less: Predecessor loss prior to the IPO (from January 1, 2014 through October 14, 2014)
(7,206
)
 
 
 
 
Net loss attributable to general and limited partner interests in USD Partners LP subsequent to the IPO (from October 15, 2014 through December 31, 2014)
$
(472
)
 
 
 
 
Net income (loss) attributable to limited partner interest
$
(7,524
)
 
$
6,274

 
$
451,366

Net income (loss) per common unit (basic and diluted)
$
(0.29
)
 
$
0.54

 
$
39.06

Net income (loss) per subordinated unit (basic and diluted)
$
(0.63
)
 
$
0.54

 
$
39.06

 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
Net cash provided by operating activities
$
(3,085
)
 
$
9,239

 
$
1,798

Net cash used in investing activities
(34,204
)
 
(56,114
)
 
(773
)
Net cash provided by (used in) financing activities
45,705

 
44,885

 
(25,227
)
Net cash provided by discontinued operations
24,241

 
5,168

 
25,687

 
 
 
 
 
 
Balance Sheet Data (at period end)
 
 
 
 
 
Property and equipment, net
$
84,059

 
$
61,364

 
$
7,881

Total assets
153,652

 
107,268

 
58,934

Credit facility
81,358

 
30,000

 
30,000

Total liabilities
112,985

 
104,665

 
45,548

Partners' Capital
 
 
 
 
 
Predecessor equity

 
4,003

 
13,391

Common units
128,097

 
   ––

 

Class A units
550

 
   ––

 

Subordinated units
(87,978
)
 
   ––

 

General Partner
103

 

 

Accumulated other comprehensive loss
(105
)
 
(1,400)

 
(5)

Total Partners Capital
$
40,667

 
$
2,603

 
$
13,386

 
 
 
 
 
 
Operating Information
 
 
 
 
 
Average daily terminal throughput (bpd)
38,912

 
15,533

 
15,871

 
 
 
 
 
 
Non-GAAP Measures
 
 
 
 
 
Adjusted EBITDA
$
15,266

 
$
1,971

 
$
3,621

Distributable cash flow
$
11,577

 
$
116

 
$
1,020



47




Non- GAAP Financial Measures
Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income before depreciation and amortization, interest and other income, interest and other expense, unrealized gains and losses associated with derivative instruments, foreign currency transaction gains and losses, income taxes, non-cash expense related to our equity compensation program, discontinued operations, adjustments related to deferred revenue associated with minimum monthly commitment fees and other items which management does not believe reflect the underlying performance of our business. We define Distributable Cash Flow ("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. Adjusted EBITDA and DCF are both non-GAAP, supplemental financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
 
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. We further believe that Adjusted EBITDA and DCF information enhances an investor's understanding of our business' ability to generate cash for payment of distributions and other purposes. The GAAP measures most directly comparable to Adjusted EBITDA are net income and cash flow from operating activities. Adjusted EBITDA should not be considered an alternative to net income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and these measures may vary among other companies. As a result, Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

48




The following table sets forth a reconciliation of Adjusted EBITDA and DCF to their most directly comparable financial measures calculated and presented in accordance with GAAP:

Year Ended December 31,  

2014

2013 

2012 

(in thousands)
Reconciliation of Adjusted EBITDA and Distributable Cash Flow to net cash flows provided by operating activities and net income (loss):





Net cash flows provided by operating activities
$
(3,085
)

$
9,239


$
1,798

Add (deduct):








Discontinued operations


8,243


459,522

Depreciation
(2,631
)

(502
)

(490
)
Gain associated with derivative instruments
1,536





Settlement of derivative contracts
(344
)
 

 

Bad debt expense
(1,424
)




Amortization of deferred financing costs
(1,056
)

(1,420
)

(1,216
)
Unit based compensation expense
(550
)
 

 

Changes in accounts receivable and other assets
8,511


5,657


3,519

Changes in accounts payable and accrued expenses
2,372


(6,590
)

(1,888
)
Changes in deferred revenue and other liabilities
(17,497
)

(8,225
)

(668
)
Change in restricted cash
6,490

 

 

Net income (loss)
(7,678
)

6,402


460,577

Add (deduct):








Interest expense
4,825


3,241


2,050

Depreciation
2,631


502


490

Provision for income taxes
186


30


26

EBITDA
(36
)

10,175


463,143

Add (deduct):








Unrealized gain associated with derivative instruments
(1,192
)




Unit based compensation expense
550





Foreign currency transaction loss (1)
4,850


39



Unrecovered reimbursable freight costs (2)
1,616





Deferred revenue associated with minimum commitment fees (3)
9,478





Discontinued operations


(8,243
)

(459,522
)
Adjusted EBITDA
15,266


1,971


3,621

Add (deduct):








Cash paid for income taxes
(101
)

(26
)
 
(38
)
Cash paid for interest
(3,588
)

(1,829
)
 
(2,563
)
Distributable cash flow
$
11,577


$
116


$
1,020

    
(1) 
Represents foreign exchange transactional expenses associated with our Hardisty rail terminal.
(2) 
Represents costs incurred associated with unrecovered reimbursable freight costs related to the initial delivery of railcars in support of the Hardisty rail terminal.
(3) 
Represents deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to the customers. Amounts presented are net of corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with recognition of revenue. Refer to additional discussion of these items in Note 6 of our consolidated financial statements included in Part II, Item 8 of this Annual Report.

 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations


49




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 beginning 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, we, our, us or like terms used in the present tense or prospectively (periods beginning on or after October 15, 2014) refer to USD Partners LP and its subsidiaries. References to the Predecessor, we, our, us, or like terms, when used in a historical context (periods prior to October 15, 2014), refer to the following subsidiaries, collectively, that were contributed to USD Partners in connection with our initial public offering of 9,120,000 common units completed on October 15, 2014: San Antonio Rail Terminal LLC, USD Logistics Operations GP LLC, USD Logistics Operations LP, USD Rail LP, USD Rail Canada ULC, USD Rail International, USD Terminals Canada ULC, USD Terminals International and West Colton Rail Terminal LLC , collectively, the “Contributed Subsidiaries." The Predecessor also includes the membership interests in the following five subsidiaries of USD which operated crude oil rail terminals that were sold in December 2012: Bakersfield Crude Terminal LLC, Eagle Ford Crude Terminal LLC, Niobrara Crude Terminal LLC, St. James Rail Terminal LLC, and Van Hook Crude Terminal LLC, collectively known as the “Discontinued Operations.” 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.

Overview and Recent Developments

We are a fee-based, growth-oriented master limited partnership formed by USD to acquire, develop and operate energy-related rail terminals and other high-quality and complementary midstream infrastructure assets and businesses. Our assets consist primarily of: (i) an origination crude-by-rail terminal in Hardisty, Alberta, Canada, with capacity to load up to two 120-railcar unit trains per day and (ii) two destination unit train-capable ethanol rail terminals in San Antonio, Texas, and West Colton, California, with a combined capacity of approximately 33,000 bpd. Our rail terminals provide critical infrastructure allowing our customers to transport energy-related products from multiple supply regions to numerous demand markets that are dependent on these products. In addition, we provide railcar services through the management of a railcar fleet consisting of approximately 3,099 active railcars, as of December 31, 2014, that are committed to customers on a long-term basis, with an additional 650 railcars expected to be available for service during the first half of 2015. We generate substantially all of our operating cash flow by charging fixed fees for handling energy-related products and providing related services. We do not take ownership of the underlying commodities that we handle nor do we receive any payments from our customers based on the value of such commodities. Rail transportation of energy-related products provides efficient and flexible access to key demand markets on a relatively low fixed-cost basis, and as a result has become an important part of North American midstream infrastructure.
Market Update

After reaching highs of over $100 per barrel during the first half of 2014, crude oil prices underwent a rapid decline, with Brent and West Texas Intermediate ("WTI") reaching prices below $50 early in the first quarter of 2015. Over the same period, the spread between many benchmark crude oil prices narrowed. Crude oil loaded at our Hardisty rail terminal is priced off of the Western Canadian Select benchmark ("WCS"). Demand for WCS is primarily influenced by its spread or discount to WTI, Brent or Maya as heavy crude is consumed by refiners who may import other grades of foreign crude oil as input alternatives which are typically priced off of these benchmark crude oils.

In the fourth quarter of 2014, a number of fundamental market factors contributed to the narrowing of the spread between WCS and other crude oil benchmarks, including demand for WCS for line fill for additional pipeline connectivity to the U.S. Gulf Coast, new demand for WCS associated with additional rail and pipeline capacity, and Western Canada upgrader outages which caused WCS supply disruptions. This narrowing of spreads caused actual volumes at our Hardisty rail terminal to be lower than those implied by our minimum monthly commitment fees. Despite the current commodity price environment, we believe our customers continue to value the optionality rail provides on a low fixed-cost basis. Commodity prices have historically been volatile, and rail provides flexibility and access to best markets to help producers and refiners capture the value this volatility provides.

50




Initial Public Offering of Common Units and Related Transactions

On October 15, 2014, we completed the IPO of 9,120,000 of our common units, representing a 42.8% limited partner interest in us, for proceeds of approximately $145 million after underwriting discounts, commissions and structuring fees. On the same date, we entered into a five-year, $300 million senior secured credit agreement, the Credit Facility, comprised of a $200 million revolving credit facility, the Revolving Credit Facility, and a $100 million term loan, the Term Loan Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Facility is a five-year committed facility that matures October 15, 2019, unless amended or extended. We also completed other transactions in connection with the closing of our IPO pursuant to which USD conveyed to us its ownership interests in each of its subsidiaries that own or operate the Hardisty, San Antonio and West Colton rail terminals and the railcar business. In exchange for these ownership interests, we: (1) issued to USD Group LLC 1,093,545 of our common units and all 10,463,545 of our subordinated units, currently representing an aggregate 54.2% limited partner interest, (2) assumed $30 million of borrowings under a senior secured credit agreement payable to Bank of Oklahoma and (3) granted USD Group LLC the right to receive a $100 million distribution. Additionally, we issued our general partner 427,083 General Partner Units, representing a 2.0% general partner interest in us, as well as all of our incentive distribution rights. We used the net proceeds from our IPO as follows (in millions):
Net Proceeds from the IPO
 
$
145.0

Less:
 
 
Reimbursement of USD Group LLC for IPO expenses
 
(7.5
)
Payment of debt issuance costs
 
(2.9
)
Repayment of Bank of Oklahoma debt
 
(30.0
)
Repayment of bank indebtedness of subsidiary
 
(67.8
)
Net cash retained
 
$
36.8


We also borrowed the Canadian equivalent of U.S. $100 million on our Term Loan Facility, as discussed below, which we distributed to USD Group LLC pursuant to the right we granted them in connection with our IPO.

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 aid in resource allocation decisions and to assess operational performance.
 
Terminalling Services
 
We generate substantially all of our operating cash flow by charging fixed fees for handling energy-related products and providing related services. We do not take ownership of the underlying products that we handle nor do we receive any payments from our customers based on the value of such products. Thus, we have no direct exposure to risks associated with fluctuating commodity prices, although these risks could indirectly influence our activities and results of operations over the long term.
 
Hardisty Rail Terminal Services Agreements.    We have entered into terminal services agreements with seven high-quality counterparties or their subsidiaries: Cenovus Energy, Gibson, Phillips 66, J. Aron & Company, Suncor Energy, Total and USD Marketing LLC. Substantially all of the terminalling capacity at our Hardisty rail terminal is contracted under multi-year, take-or-pay terminal services agreements subject to inflation-based escalators. Furthermore, approximately 83% of the contracted utilization at our Hardisty rail terminal is contracted with subsidiaries of five investment grade companies, including major integrated oil companies, refiners and marketers. All of these counterparties are obligated to pay a minimum monthly commitment fee and can load a maximum allotted number of unit trains or barrels per month. If a customer loads fewer unit trains or barrels in any given month than its maximum allotted amount, that customer will be required to pay us a minimum monthly commitment fee, but they will also receive

51




a credit for up to six months that will allow that customer to load the unutilized unit trains or barrels, subject to availability. We will receive a per-barrel fee on any volumes handled in excess of the customers' maximum allowed volume, to the extent the additional volume is not subject to the credit discussed above. 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. Each of the terminal services agreements with our Hardisty rail terminal customers has an initial contract term of five years. The initial terms of six of these agreements commenced between June 30, 2014 and August 1, 2014, and the seventh agreement commenced on October 1, 2014.
 
San Antonio and West Colton Rail Terminal Services Agreements.    We have entered into terminal services agreements with a subsidiary of an investment grade company for our San Antonio rail terminal and our West Colton rail terminal pursuant to which that customer pays us per gallon fees based on the amount of ethanol offloaded at the terminals. The San Antonio terminal services agreement was originally scheduled to expire in August 2015. On January 22, 2015, the Partnership entered into an amendment with our customer at our San Antonio rail terminal whereby the service agreement will automatically extend for two additional 18 month terms unless the customer provides written notice six months prior to the end of a term. The customer did not provide notice to terminate the agreement, and the term of the agreement now extends to February 2017. The current agreement entitles the customer to 100% of the terminal’s capacity, subject to our right to seek additional customers if minimum volume usage thresholds are not met. Our San Antonio rail terminal is located within five miles from San Antonio’s gasoline blending terminals and is the only ethanol rail terminal in a 20-mile radius. The West Colton terminal services agreement has been in place since July 2009 and is terminable at any time by either party. Our West Colton rail terminal is located less than one mile from gasoline blending terminals that supply the greater San Bernardino and Riverside County-Inland Empire region of Southern California and is the only ethanol rail terminal in a ten-mile radius. We are currently in the process of seeking permits to construct an approximately one-mile pipeline directly from our West Colton rail terminal to the Kinder Morgan Inc. gasoline blending terminals, which, if approved and constructed, may result in additional long-term volume commitments and cash flows.
 
Fleet Services
 
We provide fleet services for a railcar fleet consisting of 3,099 active railcars as of December 31, 2014, with an additional 650 railcars expected to be available for service in the first half of 2015. We do not own any railcars. Affiliates of USD lease 3,096 of the railcars in our fleet from third parties, including the additional 650 railcars expected to be available for service in the first half of 2015. We directly lease 653 railcars from third parties. We have entered into master fleet services agreements with a number of customers for the use of the 653 railcars in our fleet that we lease directly. We have also entered into services agreements with affiliates of USD for the provision of fleet services with respect to the 3,096 railcars which they lease from third parties. These agreements are on a take-or-pay basis for periods ranging from five to nine years with a weighted average remaining life of 6.5 years for agreements dedicated to customers of our Hardisty rail terminal. In the aggregate, these master fleet services agreements have a weighted-average life of 5.2 years. Under our master fleet services agreements with our customers and the services agreements with affiliates of USD, we provide customers with railcar-specific fleet services associated with the transportation of crude oil, which may include, among other things, the provision of relevant administrative and billing services, the 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. We typically charge our customers, including the affiliates of USD, monthly fees per railcar that include a component for railcar use (in the case of our directly-leased railcar fleet) and a component for fleet services. Approximately 66% of our current railcar fleet is dedicated to customers of our terminals. The remaining 34% of the railcar fleet is dedicated to a customer of terminals belonging to subsidiaries we previously sold.
 
We also contract with railroads on behalf of some of our customers to arrange for the movement of railcars from our Hardisty rail terminal to the destinations selected by our customers. We are the contracting party with the railroads for these shipments, and are responsible to the railroads for the related fees charged by the railroads, for which we are 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.”

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How We Evaluate Our Operations
 
Our management uses a variety of financial and operating metrics to evaluate our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) volumes; (ii) Adjusted EBITDA and DCF; and (iii) operating and maintenance expenses. We define Adjusted EBITDA and DCF below.
 
Volumes
 
The amount of Terminalling services revenue we generate depends on both minimum customer commitment fees and the volumes of crude oil and biofuels that we handle at our rail 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 as well as the spreads between the benchmark prices for these products. Although customers at our Hardisty rail terminal have committed to minimum monthly fees under their terminal services agreements with us, which will generate the vast majority of our Terminalling services revenue, our results of operations will also be impacted by:
our customers’ utilization of our terminals in excess of their minimum monthly commitment fees;
our ability to identify and execute accretive acquisitions and organic expansion projects and capture our customers’ 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 rail terminals and provide additional ancillary services at those terminals.
 
Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income before depreciation and amortization, interest and other income, interest and other expense, unrealized gains and losses associated with derivative instruments, foreign currency transaction gains and losses, income taxes, non-cash expense related to our equity compensation program, discontinued operations, adjustments related to deferred revenue associated with minimum monthly commitment fees and other items which management does not believe reflect the underlying performance of our business. We define 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. Adjusted EBITDA and DCF are both non-GAAP, supplemental financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:

our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
 
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. We further believe that Adjusted EBITDA and DCF information enhances an investor's understanding of our business' ability to generate cash for payment of distributions and other purposes. The GAAP measures most directly comparable to Adjusted EBITDA are net income and cash flow from operating activities. Adjusted EBITDA should not be considered an alternative to net income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and these measures may vary among other companies. As a result, Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
 

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Operating and Maintenance Expenses
 
Our management seeks to maximize the profitability of our operations by effectively managing operating and maintenance expenses. Given that we generate a vast majority of our Adjusted EBITDA and DCF from our newly constructed Hardisty rail terminal, which was completed on June 30, 2014, we do not expect to incur significant maintenance capital expenditures in the near term to maintain the operating capacity of our assets. We record routine maintenance expenses associated with operating our assets in "Selling, general and administrative" costs in our consolidated statements of operations. Our operating and maintenance expenses are comprised primarily of repairs and maintenance expenses, subcontracted rail expenses, utility costs, insurance premiums and related property taxes. 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. Our expenses typically remain relatively stable, but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses.
 
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 to the 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 impacted.
 
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, which, due to potential changes in environmental and gasoline blending regulations, we expect will play a more pervasive role in the fuel for transportation market over time. 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 impacted.

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 we provide and perform railcar-specific fleet services for 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 materially impacted in the near term because of 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 terminal services agreements could be impacted by a long-term reduction in supply or demand.
 
Deferred Revenues Generated from Our Hardisty Operations

Under the terminal services agreements we have entered into with customers of our Hardisty rail 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 rail terminal. If a customer loads fewer unit trains or barrels than its maximum allotted amount in any given month, that customer will receive a credit for up to six months to offset fees on throughput in excess of their minimum monthly commitments in future periods, to the extent capacity is available for the excess volume. In the fourth quarter of 2014, throughput volumes were below those implied by the minimum commitment fees. As such, we recorded the portion of customer payments in excess of amounts paid for volumes

54




actually shipped as deferred revenues on our consolidated balance sheet. The lower throughput volumes did not affect our Adjusted EBITDA, DCF, or our ability to pay our minimum quarterly distribution, since such deferred revenue does not affect our cash flow. Furthermore, we expect to recognize as revenue any deferred revenue incurred in the fourth quarter of 2014 not later than the end of the second quarter 2015 when these “make-up rights” are either used or expire. The utilization or expiration of the make-up rights during 2015 will not affect our cash flows, since the fees associated with such volumes were previously collected. Additional discussion regarding make-up rights and deferred revenues is included in Note 6. Deferred Revenues to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data of this Annual Report.

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 crude oil and other liquid hydrocarbon materials. Additionally, we are subject to regulations governing railcar design and evolving regulations pertaining to the shipment of liquid hydrocarbons by rail. Please read Item 1. Business—Environmental Regulation. Similar to other industry participants, compliance with existing and anticipated environmental laws and regulations 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 transit as an alternate transportation option. 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 Adjusted EBITDA and DCF, we believe that as a result, consumers of our services place additional value on utilizing established and reputable third-party providers to satisfy their rail terminalling and logistics needs, which would 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 pursue strategic acquisitions that will provide attractive returns to our unitholders, including high-quality and complementary midstream infrastructure assets and businesses from USD as well as third parties. We intend to leverage our industry relationships and market knowledge to successfully execute on such opportunities, which we intend to pursue both independently and jointly with USD. We have entered into an omnibus agreement with USD and USD Group LLC, pursuant to which USD Group LLC has granted us a right of first offer on the Hardisty Phase II and Hardisty Phase III projects for a period of seven years after the closing of our IPO. Please read Item 1. Business—Our Growth Opportunities—Hardisty Phase II and Phase III Expansions. USD and USD Group LLC have also granted us a right of first offer during this seven-year period on any additional midstream infrastructure assets and businesses that they may develop, construct or acquire. Please read Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Omnibus Agreement. We cannot assure you that USD will be able to develop or construct, or that we will be able to acquire, any other midstream infrastructure project including the Hardisty Phase II or Hardisty Phase III projects. Among other things, the ability of USD to develop the Hardisty Phase II and Hardisty Phase III projects, 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 USD Group LLC are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer, including the Hardisty Phase II and Hardisty Phase III projects. 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 the Hardisty Phase II and Hardisty Phase III 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 read Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners. If we are unable to acquire the Hardisty Phase II or Hardisty Phase III projects from USD Group LLC, these expansions may compete directly with our Hardisty rail 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

55




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 reevaluate any future expansion projects, including the Hardisty Phase II and Hardisty Phase III projects. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our DCF.
 
Interest Rate Environment
 
The credit markets have recently experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten to counter possible inflation, resulting in higher interest rates. Should interest rates rise, our financing costs would increase accordingly. This could affect our future ability to access the debt capital markets to the extent we may need to fund our growth. Additionally, as with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and an 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.
 
Factors Affecting the Comparability of Our Financial Results
 
Our future results of operations will not be comparable to our Predecessor’s historical results of operations for the reasons described below.
 
Hardisty Operations and Discontinued Operations
 
Our Predecessor’s historical results of operations include revenues and expenses related to (i) the construction of our Hardisty rail terminal, (ii) the operation of our San Antonio and West Colton rail terminals, (iii) our railcar fleet services throughout North America and (iv) the operations of our Hardisty rail terminal, which commenced operations in June 2014. Costs incurred in the Predecessor periods with respect to the Hardisty rail terminal are primarily related to pre-operational activities.
 
Selling, General and Administrative Costs
 
Our Predecessor’s historical results of operations include a $1.2 million management fee each year for the West Colton and San Antonio rail terminals. In addition, our historical selling, general and administrative costs include certain expenses allocated by our sponsor for corporate costs including insurance, professional fees, facilities, information services, human resources and other support departments, as well as direct expenses. These allocated expenses were charged or allocated to us primarily on the basis of direct usage when identifiable, with the remainder allocated evenly across the number of operating subsidiaries or allocated based on budgeted volumes or projected revenues. Our sponsor charges us for the management and operation of our assets, including an annual fee of approximately $2.5 million for 2015, for the provision of various centralized administrative services and allocated general and administrative costs and expenses incurred by them on our behalf.
 
We expect to incur unit based compensation expense associated with the Class A units granted to certain executive officers and other key employees of our general partner and to recognize the expense related to each Class A Vesting Tranche ratably over its requisite service period. We also expect to incur additional general and administrative expenses annually as a result of being a publicly traded partnership, consisting of costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, Sarbanes-Oxley Act compliance, stock exchange listing, registrar and transfer agent fees, incremental director and officer liability insurance and director compensation. These additional general and administrative expenses are not reflected in our historical financial statements.

Income Tax Expense
 
Prior to our IPO, we were included in our sponsor’s consolidated U.S. federal income tax return, in which we were treated as an entity disregarded as separate from our sponsor for income tax purposes. Subsequent to the closing of the IPO, we are treated as a partnership for U.S. federal income tax purposes, with each partner being separately

56




taxed on its share of taxable income; therefore, there is no U.S. federal income tax expense reflected in our Predecessor financial statements. However, our Hardisty rail terminal is subject to Canadian income and withholding taxes that result from taxable income and cash distributions generated by our Canadian operations and certain distributions from our Canadian subsidiaries. We anticipate paying income taxes on our Canadian income at a rate of 25% and will be required to pay withholding taxes on cash distributed to us from our Canadian subsidiaries at a rate of 5%. We have a Canadian loss carryover of approximately $8.5 million as of December 31, 2014 of which $4.7 million could be applied towards future ordinary taxable income generated by our Canadian terminals and railcar businesses. We also have a loss carryover for U.S. federal income tax purposes of approximately $0.7 million as of December 31, 2014, all of which could be applied towards future ordinary taxable income generated by our U.S. railcar business. In addition, in order to maintain our status as a partnership for U.S. federal income tax purposes, we have elected to conduct a portion of our business, relating to railcar fleet services, in a subsidiary that is treated as a corporation for U.S. federal income tax purposes. We are in the process of requesting a ruling from the IRS upon which, if granted, we may rely with respect to the qualifying nature of the income from this business. If the IRS is unwilling or unable to provide a favorable ruling with respect to the income from our railcar fleet services business, we will be subject to corporate-level tax on the revenues generated by this business. Conversely, if the IRS does provide a favorable ruling, we may choose to conduct our future railcar fleet services business in a tax pass-through entity. Such restructuring may result in a significant, one-time tax liability and other costs, which may reduce our cash available for distribution.
 
Financing
 
Historically, our operations were financed by cash generated from operations and intercompany loans from our sponsor. On October 15, 2014, in connection with the closing of our IPO, we entered into a five-year, $300.0 million senior secured credit agreement (the “Credit Agreement”) comprised of a $100.0 million term loan (borrowed in Canadian dollars and maturing on July 14, 2019) and $200.0 million revolving credit facility (maturing on October 15, 2019), which will automatically be expanded to $300.0 million proportionately as the term loan principal is reduced. As of March 24, 2015, we had $6.0 million drawn on our Revolving Credit Facility and no change to the Canadian dollar amounts outstanding under our Term Loan Facility. Please read “Liquidity and Capital Resources.”

We anticipate using our cash flows generated in Canada initially to repay borrowings under our term loan and anticipate making equivalent borrowings under our revolving credit facility to fund distributions to our unitholders. Following repayment of the term loan and absent the incurrence of additional Canadian debt, we anticipate distributing Canadian cash flows to partially fund distributions to our unitholders which could be subject to Canadian witholding taxes.
 
Cash Distributions
 
We intend to make minimum quarterly distributions of $0.2875 per common unit ($1.15 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We intend to pay distributions no later than 60 days after the end of each quarter. We paid our initial distribution on February 13, 2015, which represent a prorated amount for the quarter ending December 31, 2014, to unitholders of record on February 9, 2015.

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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 ended December 31, 2014, 2013 and 2012.
 
For the Year Ended December 31,
 
2014
 
2013
 
2012
 
(in thousands)
Operating income:
 
 
 
 
 
Terminalling services
$
2,944

 
$
1,026

 
$
3,366

Fleet services
(429
)
 
817

 
(109
)
Corporate and Other
(1,868
)
 
(374
)
 
(126
)
Total Operating income
647

 
1,469

 
3,131

Interest expense
4,825

 
3,241

 
2,050

Gain associated with derivative instruments
(1,536
)
 

 

Foreign currency transaction loss
4,850

 
39

 

Provision for income taxes
186

 
30

 
26

Income (loss) from continuing operations
(7,678
)
 
(1,841
)
 
1,055

Income from discontinued operations

 
8,243

 
459,522

Net income (loss)
$
(7,678
)
 
$
6,402

 
$
460,577

Summary Analysis of Operating Results

Year ended December 31, 2014 compared to the year ended December 31, 2013

The change in our operating results for the year ended December 31, 2014, compared with our results for the same period of 2013 were largely driven by the commencement of operations at our Hardisty rail terminal facility in June 2014. Our Hardisty rail terminal operations contributed approximately $2.2 million to the operating income of our Terminalling services business, which was partially offset by lower operating income in our Fleet services business and additional selling, general and administrative costs, primarily related to our omnibus agreement and public partnership expenses that we do not allocate to our segments. Additionally our operating results for the year ended December 31, 2014 were negatively affected by additional interest expense associated with amounts outstanding on the Credit Facility we entered into in connection with our IPO and foreign currency transaction losses related to our Canadian operations, partially offset by gains on our derivative instruments. A more comprehensive discussion of our operating results by segment is presented below.
Year ended December 31, 2013 compared to year ended December 31, 2012
 
The change in our operating results for the year ended December 31, 2013, compared with the results we achieved for the same period of 2012, primarily resulted from the impact of certain fixed overhead costs that were retained subsequent to the disposition of five terminals. In addition, the San Antonio rail terminal and West Colton rail terminal experienced slightly lower throughput volumes and lower realized rates during the year ended December 31, 2013. The lower realized rates were primarily attributable to a reduction in the rates payable at our San Antonio rail terminal as a result of a rate reduction negotiated with our customer in August 2012. Additionally, we incurred higher interest costs in connection with commencing construction on our Hardisty rail terminal during 2013.


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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 rail terminals for each of the years ended December 31, 2014, 2013, and 2012.
 
For the Year Ended December 31,
 
2014
 
2013
 
2012
 
(in thousands, except bpd)
Revenues:
 
 
 
 
 
Terminalling services revenue
$
21,765

 
$
7,130

 
$
8,703

Railroad incentives
719

 

 

Total revenues
22,484

 
7,130

 
8,703

Operating costs:
 
 
 
 
 
Subcontracted rail services
6,994

 
1,898

 
1,847

Pipeline fees
3,625

 

 

Selling, general and administrative
6,290

 
3,704

 
3,000

Depreciation
2,631

 
502

 
490

Total operating costs
19,540

 
6,104

 
5,337

Operating income
2,944

 
1,026

 
3,366

Interest expense
3,600

 
3,241

 
2,050

Gain associated with derivative instruments
(1,536
)
 

 

Foreign currency transaction loss
4,406

 
39

 

Provision for income taxes
47

 
21

 
26

Income (loss) from continuing operations
$
(3,573
)
 
$
(2,275
)
 
$
1,290

Average daily terminal throughput (bpd)
38,912

 
15,533

 
15,871


Year ended December 31, 2014 compared to the year ended December 31, 2013
Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $15.4 million to $22.5 million for the year ended December 31, 2014, compared with $7.1 million the year ended December 31, 2013, primarily due to the commencement of operations at our Hardisty rail terminal at the end of June 2014, which increased our average daily terminal throughput volumes by 23,379 bpd.

Terminalling services segment revenue for the year ended December 31, 2014, excludes $12.6 million of revenue that we have deferred and recognized as a short-term liability on our consolidated balance sheet. We have deferred recognizing this revenue in connection with the minimum monthly commitment fees paid by customers at our Hardisty rail terminal in excess of their actual throughput volumes due to the make-up rights we have granted our customers under our terminal services agreements with them. These make-up rights can be utilized by our customers for periods up to six months to offset throughput volumes in excess of their minimum monthly commitments in future periods, to the extent capacity is available for the excess volume. We expect to recognize the deferred amounts as our customers use these rights, upon expiration of the make-up period, or when our customers' ability to utilize those rights is determined to be remote.

Railroad Incentive Payments

Historically, we have received incentive payments from railroads in connection with events that are projected to increase incremental traffic on their network such as large capital projects. With respect to our Hardisty rail terminal, through mid-2017 we have the right to receive up to CAD $12.5 million in gross incentive payments payable based on the number of railcars loaded for certain customers through mid-2017. A portion of these incentive payments increases

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the pipeline fees payable to Gibson. We earned approximately $0.7 million of railroad incentive payments during 2014 in connection with the operation of our Hardisty rail terminal.

Operating Costs

The operating costs of our Terminalling services segment increased $13.4 million to $19.5 million for the year ended December 31, 2014, as compared with $6.1 million for the year ended December 31, 2013. The increase is primarily due to the commencement of operations of our Hardisty rail terminal in June 2014, which drove the following changes for the year ended December 31, 2014 as compared with December 31, 2013: (i) an increase of $5.1 million in Subcontracted rail services costs, (ii) an increase of $3.6 million in Pipeline fees, (iii) an increase of $2.6 million in Selling, general and administrative expense, and (iv) an increase of $2.1 million in depreciation expense.
 
Subcontracted rail services. Subcontracted rail services costs increased $5.1 million to $7.0 million for the year ended December 31, 2014, compared to $1.9 million for the year ended December 31, 2013, primarily due to additional costs incurred in Canada related to new activity at the Hardisty rail terminal.
Pipeline fees. Pipeline fees were $3.6 million during the year ended December 31, 2014, due to the commencement of operations at our Hardisty rail terminal. The pipeline fees we incur are derived from a collaborative arrangement that we have with Gibson whereby we pay fees to Gibson for the transportation of crude oil on their pipeline to the Hardisty rail terminal. We did not have any pipeline fees in the year ended December 31, 2013.
Selling, general and administrative. Selling, general and administrative expenses increased $2.6 million to $6.3 million for the year ended December 31, 2014, from $3.7 million for the year ended December 31, 2013. The increase was primarily due to the commencement of operations at the Hardisty rail terminal during 2014.

Depreciation. Depreciation expense increased $2.1 million to $2.6 million for the year ended December 31, 2014, from $0.5 million for the year ended December 31, 2013, primarily due to the commencement of operations at the Hardisty rail terminal during 2014.

Other Expenses
 
Interest expense. Interest expense for our Terminalling services segment increased by $0.4 million to $3.6 million for the year ended December 31, 2014, from $3.2 million for the year ended December 31, 2013, primarily due to interest costs we incurred in connection with the construction of our Hardisty rail terminal which was placed into service in June 2014 and the amortization of deferred financing costs associated with an amendment to the existing credit facility in late 2013.

Gain associated with derivative instruments. We recognize all derivative financial instruments at fair market value, hence we recorded a gain of $1.5 million for the year ended December 31, 2014, in our Terminalling services segment on derivative contracts in place to mitigate our exposure to fluctuations in foreign currency exchange rates resulting from the commencement of our Hardisty rail terminal operations. We did not have similar derivative arrangements in place during the year ended December 31, 2013, and as a result, we did not recognize any gain or loss on derivative activities during that period.

Foreign currency transaction loss Our Terminalling services segment recognized foreign currency transaction losses of $4.4 million for the year ended December 31, 2014, in connection with the commencement of our Hardisty rail terminal operations. We remeasure the U.S. dollar denominated monetary items of our international operations at the applicable rates of exchange throughout the reporting period, with any corresponding foreign currency exchange gains or losses from remeasurement recorded in our consolidated statements of operations. Prior to 2014, we did not have any significant foreign operations that would generate material transaction gains and losses. Our foreign currency transaction loss primarily consists of losses incurred as a result of remeasurement of U.S. dollar denominated bank debt in periods prior to our IPO and the recapitalization transactions completed in contemplation of our IPO, as well as routine transactions with external customers.

Provision for income taxes. Provision for income taxes for our Terminalling services segment was slightly higher at $47 thousand for the year ended December 31, 2014, as compared with $21 thousand the year ended December 31, 2013, and consists primarily of state franchise taxes associated with our ethanol terminals and foreign minimum corporate tax.

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Year ended December 31, 2013 compared to year ended December 31, 2012
 
Revenues
 
Terminalling services segment revenue decreased $1.6 million, primarily due to (i) a decrease in average daily terminal throughput volumes of 338 bpd from 15,871 bpd for the year ended December 31, 2012 to 15,533 bpd for the year ended December 31, 2013 and (ii) a decrease in average realized rates per gallon for the year ended December 31, 2013, compared to the average rates realized during the year ended December 31, 2012, primarily attributable to a reduction in the rates payable at our San Antonio rail terminal resulting from a rate reduction negotiated with our customer in August 2012.

Operating Costs
 
Terminalling services segment operating costs increased $0.8 million to $6.1 million for the year ended December 31, 2013, from $5.3 million for the year ended December 31, 2012, primarily due to an increase of $0.7 million in Selling, general and administrative expense.
 
Subcontracted rail services. Subcontracted rail services costs remained flat at $1.9 million for the year ended December 31, 2013, compared to $1.8 million for the year ended December 31, 2012, as these costs are generally fixed.
 
Selling, general and administrative. Selling, general and administrative expenses for our Terminalling services segment increased $0.7 million to $3.7 million in the year ended December 31, 2013, compared to $3.0 million for the year ended December 31, 2012. The increase was primarily due to pre-operational costs associated with the Hardisty rail terminal and increased direct general and administrative charges.
 
Depreciation. Depreciation expense remained flat at $0.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012.

Other Expenses
 
Interest expense. Interest expense for our Terminalling services segment increased $1.1 million to $3.2 million for the year ended December 31, 2013, compared to $2.1 million in the year ended December 31, 2012. The increase was primarily due to an increase in the average debt balance maintained from continuing operations in 2013.
 
Foreign currency transaction loss. Foreign currency transaction loss for our Terminalling services segment remained flat for the year ended December 31, 2013, as compared to the year ended December 31, 2012.
 
Provision for income taxes. Provision for income taxes for our Terminalling services segment remained flat for the year ended December 31, 2013, as compared to the year ended December 31, 2012.


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FLEET SERVICES

The following table sets forth the operating results of our Fleet Services business for each of the years ended December 31, 2014, 2013, and 2012.
 
For the Year Ended December 31,
 
2014
 
2013
 
2012
 
(in thousands)
Revenues:
 
 
 
 
 
Fleet leases
$
8,788

 
$
13,572

 
$
15,964

Fleet services
2,221

 
1,197

 
5

Freight and other reimbursables
2,605

 
4,402

 
203

Total revenues
13,614

 
19,171

 
16,172

Operating costs:
 
 
 
 
 
Fleet leases
8,788

 
13,572

 
15,964

Freight and other reimbursables
2,605

 
4,402

 
203

Selling, general and administrative
2,650

 
380

 
114

Depreciation

 

 

Total operating costs
14,043

 
18,354

 
16,281

Operating income (loss)
(429
)
 
817

 
(109
)
Interest expense

 

 

Foreign currency transaction gain
(17
)
 

 

Provision for income taxes
140

 
9

 

Income (loss) from continuing operations
$
(552
)
 
$
808

 
$
(109
)

Year ended December 31, 2014 compared to the year ended December 31, 2013

Revenues
Revenues from our Fleet services segment decreased $5.6 million to $13.6 million for the year ended December 31, 2014, compared to $19.2 million for the year ended December 31, 2013. The decline was due to a $4.8 million decrease in Fleet leases revenue and a $1.8 million decrease in Freight and other reimbursables revenue, which were partially offset by a $1.0 million increase in Fleet services revenue.
Fleet leases. Fleet leases revenue decreased $4.8 million to $8.8 million for the year ended December 31, 2014, compared to $13.6 million for the year ended December 31, 2013, primarily due to a decrease in railcar lease payments from customers, which payments, together with our obligations to make rental payments to the owners of the railcars, were assigned to an affiliate of USD. The assignment of these lease payments does not impact our Adjusted EBITDA and cash available for distribution or net income as these lease payments were historically offset by our rental payments to the owners of the railcars. 
Fleet services. Fleet services revenue increased $1.0 million to $2.2 million for the year ended December 31, 2014, compared to $1.2 million for the year ended December 31, 2013, primarily due to an increase in railcar services provided to an affiliate of USD.
Freight and other reimbursables. Freight and other reimbursables revenues decreased $1.8 million to $2.6 million for the year ended December 31, 2014, compared to $4.4 million for the year ended December 31, 2013, as we incurred less railroad freight fees on behalf of certain customers, primarily associated with the delivery and shipment of railcars in preparation for the start-up of operations at our Hardisty rail terminal. These freight fees are generally reimbursed by our customers. Freight and other reimbursables revenues were exactly offset by Freight and other reimbursables costs payable to the railroads.

Operating Costs

Operating costs of our fleet services segment decreased $4.3 million to $14.0 million for the year ended December 31, 2014, compared to $18.4 million for the year ended December 31, 2013, primarily due to a decrease of $4.8 million in Fleet leases costs and a $1.8 million decrease in Freight and other reimbursables costs, which were partially offset by an increase of $2.3 million in Selling, general and administrative expenses.

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Fleet leases costs. Fleet leases costs decreased $4.8 million to $8.8 million for the year ended December 31, 2014, compared to $13.6 million for the year ended December 31, 2013, primarily due to (i) the assignment of railcar leases to an affiliate of USD and (ii) the 2013 assignment of railcar leases associated with the sale of five subsidiaries of USD to a third party in December 2012.
Freight and other reimbursables costs. Freight and other reimbursables costs decreased $1.8 million to $2.6 million for the year ended December 31, 2014, compared to $4.4 million for the year ended December 31, 2013, as we incurred less railroad freight fees on behalf of certain customers, primarily associated with the delivery and shipment of railcars in preparation for the start-up of operations at our Hardisty rail terminal. These freight fees are generally reimbursed by our customers. Freight and other reimbursables costs were exactly offset by Freight and other reimbursables revenues.
Selling, general and administrative. Selling, general and administrative expenses for our Fleet services segment increased $2.3 million to $2.7 million for the year ended December 31, 2014, compared to $0.4 million for the year ended December 31, 2013, primarily due to a provision for bad debts associated with the aging of certain reimbursable freight costs related to a portion of our railcar fleet.
Depreciation. Our Fleet services segment does not own any significant amounts of property upon which to record depreciation expense and, as a result, did not incur depreciation expense for either of the years ended December 31, 2014 or 2013.

Other Expenses

Provision for income taxes. Provision for income taxes for our Fleet services segment was $140 thousand and $9 thousand for the years ended December 31, 2014 and 2013, respectively, primarily due to the provision for state franchise taxes.
Year ended December 31, 2013 compared to year ended December 31, 2012
 
Revenues
 
Fleet services segment revenue decreased $3.0 million to $19.2 million for the year ended December 31. 2013, compared to $16.2 million for the year ended December 31, 2012. Freight and other reimbursables revenues increased by $4.2 million and Fleet services revenue increased by $1.2 million, which were partially offset by a $2.4 million decrease in Fleet leases revenues.
 
Fleet leases. Fleet leases revenue decreased $2.4 million to $13.6 million for the year ended December 31, 2013, compared to $16.0 million for the year ended December 31, 2012, primarily due to a decrease in railcar lease payments from customers, which payments, together with our obligations to make rental payments to the owners of the railcars, were assigned to an affiliate of USD. The assignment of these lease payments does not impact our Adjusted EBITDA and distributable cash flow or net income as these lease payments were historically offset by our rental payments to the owners of the railcars.
 
Fleet services. Fleet services revenue increased by $1.2 million to $1.2 million for the year ended December 31, 2013, primarily due to an increase in railcar services provided to an affiliate of USD.
 
Freight and other reimbursables. Freight and other reimbursables revenues increased $4.2 million to $4.4 million for the year ended December 31, 2013, compared to $0.2 million for the year ended December 31, 2012, as we incurred more railroad freight fees on behalf of certain customers, primarily associated with the delivery and shipment of railcars in preparation for the start-up of operations at our Hardisty rail terminal. These freight fees are generally reimbursed by our customers. Freight and other reimbursables revenues were exactly offset by Freight and other reimbursables costs payable to the railroads.
 
Operating Costs
 
Fleet services segment operating costs increased $2.1 million to $18.4 million for the year ended December 31, 2013, compared to $16.3 million for the year ended December 31, 2012, primarily due to (i) an increase of $4.2 million in Freight and other reimbursables costs and (ii) an increase of $0.3 million in Selling, general and administrative expenses, which was partially offset by a decrease of $2.4 million in Fleet leases costs.

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Fleet leases costs. Fleet leases costs decreased $2.4 million to $13.6 million for the year ended December 31, 2013, compared to $16.0 million for the year ended December 31, 2012 , primarily due to the assignment of railcar leases to an affiliate of USD.
 
Freight and other reimbursables costs. Freight and other reimbursables costs increased $4.2 million to $4.4 million for the year ended December 31, 2013, compared to $0.2 million for the year ended December 31, 2012, as we incurred more railroad freight fees on behalf of certain customers, primarily associated with the delivery and shipment of railcars in preparation for the start-up of operations at our Hardisty rail terminal. These freight fees are generally reimbursed by our customers. Freight and other reimbursables costs were exactly offset by Freight and other reimbursables revenues.
 
Selling, general and administrative. Selling, general and administrative expenses for our Fleet services segment increased $0.3 million to $0.4 million in the year ended December 31, 2013, compared to $0.1 million the year ended December 31, 2012. The increase was primarily due to an increase in insurance costs.
 
Depreciation. Our Fleet services segment does not own any significant amounts of property upon which to record depreciation expense and, as a result, did not incur depreciation expense for either of the years ended December 31, 2013 or 2012

Other Expenses
 
Provision for income taxes. Provision for income taxes for our Fleet services segment remained flat at $9 thousand for the year ended December 31, 2013, compared to $0 the year ended December 31, 2012.

Segment Adjusted EBITDA
Our chief operating decision maker ("CODM"), regularly reviews financial information about both segments in deciding how to allocate resources and evaluate performance. Our CODM assesses segment performance based on net income before depreciation and amortization, interest and other income, interest and other expense, unrealized gains and losses associated with derivative instruments, foreign currency transaction gains and losses, income taxes, non-cash expense related to our equity compensation program, discontinued operations, adjustments related to deferred revenue associated with minimum monthly commitment fees and other items which management does not believe reflect the underlying performance of our business ("Segment Adjusted EBITDA").


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The following table provides a reconciliation of Adjusted EBITDA to income (loss) from continuing operations:
 
For the Years Ended December 31,
 
2014
 
2013
 
2012
 
(in thousands)
Adjusted EBITDA
 
 
 
 
 
Terminalling services
$
15,397

 
$
1,528

 
$
3,856

Fleet services
1,187

 
817

 
(109
)
Corporate activties (1)
(1,318
)
 
(374
)
 
(126
)
Total Adjusted EBITDA
15,266

 
1,971

 
3,621

Add (deduct):
 
 
 
 
 
Interest expense
4,825

 
3,241

 
2,050

Depreciation
2,631

 
502

 
490

Provision for income taxes
186

 
30

 
26

Unrealized gain associated with derivative instruments
(1,192
)
 

 

Unit based compensation expense
550

 

 

Foreign currency transaction loss
4,850

 
39

 

Unrecovered reimbursable freight costs
1,616

 

 

Deferred revenue associated with minimum commitment fees (2)
9,478

 

 

Income (loss) from continuing operations
$
(7,678
)
 
$
(1,841
)
 
$
1,055

    
(1) 
Corporate activities represents corporate and financing activities that are not allocated to the established reporting segments.
(2) 
Amounts presented are net of corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with recognition of revenue.

Terminalling Services Segment

Adjusted EBITDA from our Terminalling services segment increased $13.9 million to $15.4 million in the year ended December 31, 2014, compared to $1.5 million in the year ended December 31, 2013. The increase was due to an increase in revenues of $15.4 million, deferred revenue associated with the minimum monthly commitment fees of $9.5 million, and a realized gain associated with derivative instruments of $0.3 million, partially offset by an increase in operating expenses of $11.3 million. These changes are primarily due to the commencement of operations at the Hardisty rail terminal in June 2014.
Adjusted EBITDA from our Terminalling services segment decreased $2.4 million to $1.5 million in the year ended December 31, 2013, compared to $3.9 million in the year ended December 31, 2012. The decrease was due to (i) a decrease in revenues of $1.6 million primarily due to a rate reduction negotiated with our customer in San Antonio in August 2012 and (ii) an increase in Selling, general and administrative expenses driven by pre-operational costs associated with the Hardisty rail terminal as well as an increase in direct general and administrative expenses.

Fleet Services Segment
Adjusted EBITDA from our Fleet services segment increased $0.4 million to $1.2 million in the year ended December 31, 2014, compared to $0.8 million in the year ended December 31, 2013, primarily due to the commencement of operations at the Hardisty rail terminal on June 30, 2014.
Adjusted EBITDA from our Fleet services segment increased $0.9 million to $0.8 million in the year ended December 31, 2013, compared to $(0.1) million in the year ended December 31, 2012. The increase was primarily due to an increase in railcar fleet services provided to an affiliate of USD.

Discontinued Operations

On December 12, 2012, USD sold all of its membership interests in five of its subsidiaries, included in our Predecessor’s Terminalling services segment, to a large energy transportation, terminalling and pipeline company. The sales price of the subsidiaries was $502.6 million, net of working capital adjustments. USD used a portion of these

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proceeds to pay down bank debt and for distributions to its members. For the years ended December 31, 2013, and 2012, our Predecessor recorded $7.3 million and $394.3 million, respectively, as a gain on sale of discontinued operations. A sixth subsidiary, which is also included in our Predecessor’s Terminalling services segment, ceased operations. Income from these discontinued operations decreased $64.3 million from $65.2 million for the year ended December 31, 2012, to $0.9 million for the year ended December 31, 2013.

Growth Opportunities for our Operations

We are currently pursuing several expansion projects which would increase the revenue of our Terminalling and Fleet services.

Hardisty Phase II and Phase III Expansions
 
Our sponsor currently owns the right to construct and develop additional infrastructure at the Hardisty rail terminal, which could expand the number of unit trains that can be loaded from two unit trains per day to up to five unit trains per day. We refer to these expansion projects as Hardisty Phase II and Hardisty Phase III. USD is currently in the process of contracting, designing, engineering and permitting Hardisty Phase II, which would expand the capacity for handling and transportation of crude oil by two unit trains per day, which we expect would be contracted under similar multi-year take-or-pay agreements to those currently in place at our Hardisty rail terminal. Subject to receiving required regulatory approvals and obtaining required permits on a timely basis, successful contracting of the expanded capacity, and the absence of unanticipated delays in construction, USD currently anticipates that Hardisty Phase II will commence operations in the first half of 2016. Hardisty Phase III would expand capacity by one additional unit train per day and would target the loading of bitumen with very limited amounts of diluent, which could not be transported by pipeline, through the use of C&I railcars. Hardisty Phase III requires additional infrastructure to be designed, engineered, permitted and constructed. Subject to receiving required regulatory approvals and obtaining required permits on a timely basis, successful contracting of the expanded capacity, and the absence of unanticipated delays in construction, we currently anticipate that Hardisty Phase III will commence operations during 2017. We have entered into an omnibus agreement with USD and USD Group LLC, pursuant to which USD Group has granted to us a right of first offer on Hardisty Phase II and Hardisty Phase III for a period of seven years after October 15, 2014, the closing of our IPO. Additional information about the omnibus agreement and the right of first offer are included in this Annual Report under Item 13. Certain Relationships and Related Transactions, and Director Independence.
We cannot assure you that USD will be able to develop or construct, or that we will be able to acquire, any other midstream infrastructure projects, including the Hardisty Phase II or Hardisty Phase III projects. Among other things, the ability of USD to develop the Hardisty Phase II and Hardisty Phase III projects, 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 USD Group LLC are under no obligation to accept any offer we make, with respect to any asset subject to our right of first offer, including the Hardisty Phase II and Hardisty Phase III projects. 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 the Hardisty Phase II and Hardisty Phase III 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 read “Management—Special Approval Rights of Energy Capital Partners.” If we are unable to acquire the Hardisty Phase II or Hardisty Phase III projects from USD Group LLC, these expansions may compete directly with our Hardisty rail 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. 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 the Hardisty Phase II and Hardisty Phase III projects.

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LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements are to make distributions to our unitholders, finance current operations, fund capital expenditures, including potential acquisitions and the costs to construct new assets, and service our debt. Historically, our operations were financed by cash generated from operations, borrowings under our credit facility and intercompany loans from our sponsor.

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility, and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our near-term working capital and long-term capital expenditure requirements and to make quarterly cash distributions. In addition, we retained a significant portion of the proceeds from our IPO as cash on our balance sheet to fund potential future growth initiatives and for general partnership purposes. We do not expect the absence of cash flows from discontinued operations to have any impact on our future liquidity or capital resources.

Energy Capital Partners must approve any additional issuances of equity by us, which determinations may be made free of any duty to us or our unitholders. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners must approve the incurrence by or refinancing of our indebtedness outside of the ordinary course of business.

Credit Risk
 
Our exposure to credit risk may be affected by the concentration of customers due to changes in economic or other conditions. Our customers' businesses react differently to changing conditions. We believe that our credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for amounts that may be uncollectible in the future.

Contractual Obligations and Commitments
 
In the ordinary course of business activities, we enter into a variety of contractual obligations and other commitments. The following table summarizes the principal amount of our future minimum obligations and commitments that have remaining non-cancelable terms in excess of one year at December 31, 2014:
 
Payments Due by Year
 
 
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
(in thousands)
 
 
Operating services agreements(1)
$
34,198

 
$
8,460

 
$
7,549

 
$
7,700

 
$
7,854

 
$
2,635

 
$

Operating leases(2)   
35,152

 
9,273

 
5,226

 
5,051

 
4,070

 
4,070

 
7,462

Interest (3)   
14,287

 
3,151

 
3,151

 
3,151

 
3,151

 
1,683

 

Credit Facility(4)   
81,358

 

 

 

 

 
81,358

 

Omnibus Agreement(5)   
2,500

 
2,500

 

 

 

 

 

Total
$
167,495

 
$
23,384

 
$
15,926

 
$
15,902

 
$
15,075

 
$
89,746

 
$
7,462

    
(1) 
These future obligations represent labor service agreements at our rail terminal facilities.
(2) 
Future minimum lease payments under noncancelable operating leases for land, building, track, and railcars.
(3) 
Interest payable on our Credit Agreement is variable. We estimated interest through July 2019 using rates in effect on December 31, 2014.
(4) 
Principal repayment obligations under our Credit Agreement as of December 31, 2014.
(5) 
Annual fee due to our general partner under the omnibus agreement for the provision of various centralized administrative services. After 2015, this fee will be changed annually to accurately reflect the general and administrative services provided to us by USD and its affiliates.


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Cash Flows
 
The following table and discussion presents a summary of net cash provided by (used in) operating activities, investing activities and financing activities for the periods indicated.
 
For the Year Ended December 31,
2014
 
2013
 
2012
(in thousands)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
(3,085
)
 
$
9,239

 
$
1,798

Investing activities
(34,204)

 
(56,114)

 
(773)

Financing activities
45,705

 
44,885

 
(25,227)

Discontinued operations
24,241

 
5,168

 
25,687

Effect of exchange rates on cash
1,441

 
(1,498)

 
(5)

Net increase in cash and cash equivalents
$
34,098

 
$
1,680

 
$
1,480


Operating Activities
 
Net cash provided by operating activities decreased by $12.3 million to $(3.1) million for the year ended December 31, 2014, compared to $9.2 million for the year ended December 31, 2013. The decrease was primarily due to the decrease in net income and designation of restricted cash, partially offset by the net changes in working capital associated with the commencement of operations at the Hardisty rail terminal.

Net cash provided by operating activities increased by $7.4 million to $9.2 million for the year ended December 31, 2013, compared to $1.8 million for the year ended December 31, 2012. The increase was primarily due to an increase in construction-related retention payables at the Hardisty rail terminal, as well as an increase in deferred revenues associated with the railcar fleet.

Investing Activities
 
Net cash used in investing activities decreased by $21.9 million to $34.2 million for the year ended December 31, 2014, compared to $56.1 million for the year ended December 31, 2013 . The decrease was primarily due to the timing of capital expenditures made in association with the development of the Hardisty rail terminal.

Net cash used in investing activities increased by $55.3 million to $56.1 million for the year ended December 31, 2013, compared to $0.8 million for the year ended December 31, 2012 . The increase was primarily due to capital expenditures made in association with the development of the Hardisty rail terminal.

Financing Activities
 
Net cash provided by financing activities increased by $0.8 million to $45.7 million for the year ended December 31, 2014, compared to $44.9 million for the year ended December 31, 2013. The increase was primarily due to the changes in debt and net IPO proceeds, partially offset by distributions to parent.

Net cash provided by financing activities increased by $70.1 million to $44.9 million for the year ended December 31, 2013, compared to net cash used in financing activities of $25.2 million for the year ended December 31, 2012. The change was primarily due to an intercompany loan from USD to fund the development of the Hardisty rail terminal.

Discontinued Operations
 
Net cash provided by discontinued operations increased by $19.0 million to $24.2 million in the year ended December 31, 2014, compared to $5.2 million for the year ended December 31, 2013 The increase was primarily due to the 2014 receipt of escrow funds related to the sale of five subsidiaries of USD in December 2012.
 

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Net cash provided by discontinued operations decreased by $20.5 million to $5.2 million in the year ended December 31, 2013, compared to $25.7 million for the year ended December 31, 2012. The decrease was primarily due to the sale of five subsidiaries of USD in December 2012.
 
We do not expect the absence of cash flows from discontinued operations to have any impact on our future liquidity or capital resources.

Capital Requirements
 
Our historical capital expenditures have primarily consisted of the costs to construct our assets. Our operations are expected to require investments to expand, upgrade or enhance existing operations and to meet environmental and operational regulations.

Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital 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, rail lines and railcars or other complementary midstream assets from USD or third parties and the construction or development of new terminals or additional capacity at our existing rail 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.

Our historical accounting records did not differentiate between expansion, maintenance and investment capital expenditures. We did not incur any maintenance capital expenditures during the year ended December 31, 2014. Based on the nature of our operations, our assets typically require minimal to no maintenance capital expenditures. We record our routine maintenance expenses associated with our assets in "Selling, general and administrative costs" in our consolidated statements of operations. Our total growth capital expenditures for the year ended December 31, 2014 amounted to $33.7 million and were primarily in connection with the construction of our Hardisty rail terminal. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated from our operations, borrowings under our revolving credit facility, the issuance of additional partnership units or debt offerings.

Distributions
 
We intend to pay a minimum quarterly distribution of $0.2875 per unit per quarter, which equates to $6.1 million per quarter, or $24.6 million per year, based on the number of common, Class A, subordinated and general partner units outstanding as of March 24, 2015. We do not have a legal obligation to distribute any particular amount per common unit. Please read Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchase of Equity Securities”. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, if any, must approve any distributions made by us.

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Credit Agreement
 
In connection with our IPO, we entered into a five-year, $300.0 million senior secured credit agreement comprised of a $200.0 million revolving credit facility (the "Revolving Credit Facility") and a $100.0 million term loan (the "Term Loan Facility") (borrowed in Canadian dollars) with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Agreement is a five year committed facility that matures October 15, 2019, unless amended or extended. As of December 31, 2014, there was $81.4 million outstanding under the Term Loan Facility and $0 outstanding under the Revolving Credit Facility.

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. As the Term Loan Facility is repaid, availability equal to the amount of the Term Loan Facility pay-down will be transferred from the Term Loan Facility to the Revolving Credit Facility automatically, ultimately increasing availability on the Revolving Credit Facility to $300.0 million once the Term Loan Facility is fully repaid. In addition, we also have the ability to request an increase the maximum amount of the Credit Agreement by an aggregate amount of up to $100.0 million, to a total facility size of $400.0 million, subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions. The Revolving Credit Facility includes an aggregate $20.0 million sublimit for standby letters of credit and a $20.0 million sublimit for swingline loans. Obligations under the Revolving Credit Facility are guaranteed by our restricted subsidiaries, and are secured by a first priority lien on our assets and those of our restricted subsidiaries other than certain excluded assets.

The Term Loan Facility was used to fund a $100.0 million distribution to USD Group LLC and the Term Loan Facility is guaranteed by USD Group LLC. The Term Loan Facility is not subject to any scheduled amortization. Mandatory prepayments of the term loan are required from certain non-ordinary course asset sales subject to customary exceptions and reinvestment rights.

Loans under the Credit Agreement accrue interest at a per annum rate by reference, at the borrowers' election, to the London Interbank Offered Rate ("LIBOR"), the Canadian Dealer Offered Rate ("CDOR"), a base rate, or Canadian prime rate, in each case, plus an applicable margin. Our borrowings under the Credit Agreement for revolving loans bear interest at either a base rate and Canadian prime rate, as applicable plus an applicable margin ranging from 1.25% to 2.25%, or at LIBOR or CDOR, as applicable, plus an applicable margin ranging from 2.25% to 3.25%. Borrowings under the Term Loan Facility bear interest at either the base rate and Canadian prime rate, as applicable, plus a margin ranging from 1.35% to 2.35% or at LIBOR or CDOR, as applicable, plus an applicable margin ranging from 2.35% to 3.35%. The applicable margin, as well as a commitment fee on the Revolving Credit Facility, ranging from 0.375% per annum to 0.50% per annum on unused commitments, will vary based upon our consolidated net leverage ratio, as defined in our Credit Agreement.

The guaranty by USD Group LLC includes a covenant that USD Group LLC maintain a net worth (without taking into account its interests in us (either directly or indirectly)) greater than the outstanding amount of the term loan and if such covenant is breached and not cured within a certain amount of time, the interest rate on the term loan increases by an additional 1%.
 
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 business activities, engage in mergers, consolidations and other organizational changes, sell, transfer or otherwise dispose of assets or enter into burdensome agreements or enter into transactions with affiliates on terms that are not 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;