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
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	15
Item 2.	Properties	44
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	45
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	75
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	111
Item 9A.	Controls and Procedures	111
Item 9B.	Other Information	111
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	112
Item 11.	Executive Compensation	119
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	123
Item 13.	Certain Relationships and Related Transactions, and Director Independence	126
Item 14.	Principal Accountant Fees and Services	133
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	134
Signatures		135

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).

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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 unitswhich 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

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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

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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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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

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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 theresponsible 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 otherthird 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 thewastes 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 underRCRA 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 willfulmisconduct 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.

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Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchase of Equity Securities

Our common units are listed and traded on the NYSE, 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.

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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

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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.

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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

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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 numberoffundamental 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.

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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

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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

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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

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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;

• Consolidated Total Leverage Ratio of not greater than 4.50 to 1.00 (or 5.00 to 1.00 at any time after we have issued at least $150.0 million of unsecured notes). In addition, upon the consummation of a Material Acquisition

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(as defined in our Credit Facility), for the fiscal quarter in which the Material Acquisition is consummated and for two fiscal quarters immediately following such fiscal quarter (the “Material Acquisition Period”), if elected by us by written notice to the Administrative Agent given on or prior to the date of such acquisition, the maximum permitted ratio shall be increased by 0.50 to 1.00 above the otherwise relevant level; and

• after we have issued at least $150.0 million of unsecured notes, a Consolidated Senior Secured Leverage Ratio (as defined in the Credit Facility) of not greater than 3.50 to 1.00 (or 4.00 to 1.00 during a Material Acquisition Period).

Our Credit Agreement generally prohibits us from making cash distributions (subject to exceptions as set forth in the Credit Agreement) except so long as no default exists or would be caused thereby, we may make cash distributions to unitholders up to the amount of our available cash (as defined in our partnership agreement).

The Credit Agreement contains events of default, including, but not limited to (and subject to grace periods in circumstances set forth in the Credit Agreement), the failure to pay any principal, interest or fees when due, failure to perform or observe any covenant that does not have certain materiality qualifiers contained in the Credit Agreement or related loan documentation, any representation, warranty or certification made or deemed made in the agreements or related loan documentation being untrue in any material respect when made, default under certain material debt agreements, commencement of bankruptcy or other insolvency proceedings, certain changes in our ownership or the ownership of our general partner, material judgments or orders, certain judgment defaults, ERISA events or the invalidity of the loan documents. Upon the occurrence and during the continuation of an event of default under the agreements, the lenders may, among other things, terminate their commitments, declare any outstanding loans to be immediately due and payable and/or exercise remedies against us and the collateral as may be available to the lenders under the agreements and related documentation or applicable law.

As of December 31, 2014, we were in compliance with all of the covenants set forth in our Credit Facility.

OFF-BALANCE SHEET ARRANGEMENTS

In the normal course of business, we are a party to off-balance sheet arrangements relating to various operating leases and railcar lease agreements, whereby we have agreed to assign payment and obligations to affiliates of USD that are not consolidated with us. We have also entered into agreements to provide administrative services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk of non-payment by our railcar lessees from negatively impacting our financial condition and results of operations. For more information on these special purpose entities see the discussion of our relationship with the variable interest entities described in Note 7 to our consolidated financial statements for the years ended December 31, 2014, 2013 and 2012 included in Part II, Item 8 of this report. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result from these off-balance sheet arrangements.

Related party sales to the special purpose entities were $1.5 million, $1.0 million and $0 during the years ended December 31, 2014, 2013 and 2012, respectively. These sales are recorded in Fleet services—related party on the accompanying consolidated statements of operations and comprehensive income.

Related party deferred revenues from the special purpose entities were $2.5 million and $1.0 million as of December 31, 2014 and 2013, respectively, which are recorded in Deferred revenue—related party on the accompanying consolidated balance sheets.

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SUBSEQUENT EVENTS

Distribution to Partners

On January 29, 2015, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a cash distribution payable of $0.24375 per unit for the quarter ended December 31, 2014. We paid the distribution on February 13, 2015 to unitholders of record on February 9, 2015. The cash distribution represents the prorated amount of our targeted minimum quarterly distribution of $0.28750 per unit, or $1.15 on an annualized basis, for the period from October 15, 2014, the completion of our IPO through December 31, 2014. We paid $2.2 million to our public Common unitholders, $53,625 to the Class A unitholders, an aggregate of $2.8 million to USD Group LLC as the holders of Common units and our Subordinated units and $0.1 million to USD Partners GP LLC for their general partner interest.

Long-term Incentive Plan

On February 16, 2015, the board of directors of our general partner, acting in its capacity as the general partner of USDP approved the grant of an aggregate of 415,608 phantom unit awards ("Phantom Units") to directors and employees of our general partner and its affiliates under the USD Partners LP 2014 Long-Term Incentive Plan (the "LTIP"). The Phantom Units are subject to all of the terms and conditions of the LTIP and the Phantom Unit award agreements (the "Award Agreements"). Phantom Unit awards generally represent rights to receive our common units, or with respect to certain of the awards, cash equal to the fair market value of our common units, upon vesting. Grants to directors of our general partner vest after one year, and grants to employees of our general partner and its affiliates vest in four equal annual installments. Award amounts for these grants were generally determined by reference to a specified dollar amount determined based on an allocation formula which included a percentage multiplier of the grantee's base salary, among other factors, converted to a number of units based on the IPO price of our common units in October 2014 of $17.00 per unit.

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Recent Accounting Pronouncements Not Yet Adopted

Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern

In August 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016, with early adoption permitted. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.

Reporting Discontinued Operations and Disclosure of Disposals

In April 2014, FASB issued Accounting Standards Update No. 2014-08 that changes the criteria and requires expanded disclosures for reporting discontinued operations. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our selection and application of accounting policies is an important process that has developed as our business activities have evolved and as new accounting pronouncements have been issued. Accounting decisions generally involve an interpretation of existing accounting principles and the use of judgment in applying those principles to the specific circumstances existing in our business. We make every effort to comply with all applicable accounting principles and believe the proper implementation and consistent application of these principles is critical. However, not all situations we encounter are specifically addressed in the accounting literature. In such cases, we must use our best judgment to implement accounting policies that clearly and accurately present the substance of these situations. We accomplish this by analyzing similar situations and the accounting guidance governing them and consulting with experts about the appropriate interpretation and application of the accounting literature to these situations.

In addition to the above, certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures with respect to contingent assets and liabilities. The basis for our estimates is historical experience, consultation with experts and other sources we believe to be reliable. While we believe our estimates are appropriate, actual results can and often do differ from these estimates. Any effect on our business, financial position, results of operations and cash flows resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

We believe our critical accounting policies and estimates discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involve complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit Committee of the board of directors of our general partner.

The following discussion relates to the critical accounting policies and estimates for both USD Partners LP and our Predecessor. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. The preparation of consolidated financial statements requires management to make judgments, assumptions and estimates based on the best available information at the time. The following accounting policies are considered critical because they are important to the portrayal of our financial condition and results, and involve a higher degree of complexity and judgment on the part of management. Actual results may differ based on the accuracy of the information utilized and subsequent events, some over which we may have little or no control. Significant estimates by management include the estimated lives of depreciable property and equipment, recoverability of long-lived assets, and the allowance for doubtful accounts.

Accounts Receivable

Accounts receivable are primarily due from our customers, which include oil producing and petroleum refining companies, as well as marketers of petroleum, petroleum products and biofuels, for services we have provided. We perform ongoing credit evaluations of our customers. When appropriate, we use the specific identification method to estimate allowances for doubtful accounts based on our customers’ financial condition and collection history, and other pertinent factors. Accounts are written-off against the allowance when significantly past due and deemed uncollectible by management.

Depreciation

Depreciation is calculated on the straight-line method over the estimated useful lives of the assets, which range from 5 to 20 years. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property and equipment and revise our estimates as appropriate.

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Impairment of Long-lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. A long-lived asset is considered impaired when the sum of the estimated, undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset, and a significant change in the asset’s physical condition or use.

When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, an impairment loss is recognized to the extent the carrying value exceeds the estimated fair value of the long-lived asset.

Revenue Recognition

Revenues are derived from railcar loading and offloading services for bulk liquid products including crude oil, biofuels, and related products, as well as sourcing railcar fleets and related logistics and maintenance services. We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, the buyer’s price is fixed or determinable and collectability is reasonably assured. In accordance with FASB ASC 605, Revenue Recognition, the Predecessor records revenues for Fleet services on a gross basis when the Predecessor is deemed the primary obligor for the services. The Predecessor also records its revenues from reimbursable costs on a gross basis as reimbursements for out-of-pocket expenses included in revenues and operating costs.

Revenues for Terminalling services are recognized when services are provided based on the contractual rates related to throughput volumes. Certain agreements contain “take-or-pay” provisions whereby we are entitled to a minimum monthly commitment fee. We recognize the portions of these minimum monthly commitment fees paid for volumes in excess of actual throughput when the customer’s ability to make up the minimum volume has expired, in accordance with the terms of these agreements. Revenue for Fleet services and related party administrative services is recognized ratably over the contract period. Revenue for reimbursable costs is recognized as the costs are incurred. Our Predecessor has deferred revenues for amounts collected from customers in its Fleet services segment, which will be recognized as revenue when earned pursuant to contractual terms. Our Predecessor has prepaid rent associated with these deferred revenues on its railcar leases, which will be recognized as expense when incurred.

Unit Based Compensation

In connection with our IPO and as provided for in our partnership agreement, we granted non-voting Class A units to certain executive officers and other key employees of our general partner who provide services to us. The awards issued are performance-based awards that contain distribution equivalent rights.

Under Accounting Standards Codification 718, Compensation-Stock Compensation, we classify the Class A unit awards as equity grants. The fair value for award grants is determined on the grant date of the award and we recognize this value as compensation expense ratably over the requisite service period, which is the vesting period of each unit award. The Partnership has determined the fair value of the award as the price of the common units at the time of our IPO. Therefore, the Partnership considers the grant date, as defined within the accounting guidance, of these awards to be October 8, 2014. Commencement of the vesting of the Class A units also began upon the completion of our IPO.

The Class A unit awards vest in four tranches over the one, two, three and four year periods following the IPO. The Class A units receive distributions on a one to one basis with the common units during the vesting period, irrespective of the ultimate percentage of units vesting. The ultimate percentage of units vesting in each tranche depends on a performance condition: specifically, the distributions paid in the last year of the vesting period for each tranche. If distributions meet or fall below a threshold, the Class A units in that tranche are forfeited. If distributions exceed a threshold by less than a target amount, the Class A units in that tranche vest and become convertible into one common unit. If distributions exceed the threshold by more than the target amount, the Class A units in that tranche vest and

74

become convertible into more than one common unit (1.25 to 2.0 times common units per Class A unit, depending on the tranche). Distributions over the vesting period are not paid in arrearage if the Class A units become convertible into more than one common unit.

Each tranche is considered as a separate award and compensation expense for each tranche is calculated based on the performance scenario that is most probable for that tranche. At the grant date, our expectation is that it is probable that the minimum required distribution threshold for the first Class A unit tranche will be exceeded but it will not exceed the target amount. Our expectation is that it is probable that the base vesting thresholds for the second Class A unit tranche through the fourth Class A unit tranche will be exceeded by more than the target amount. Therefore, we estimated the expense for each tranche as the number of unit equity awards, multiplied by the per unit grant date fair value of those awards less estimated forfeitures in the probable vesting scenario for each tranche (equaling the applicable conversion multiple times the value of the stock excluding the expected distributions paid over the vesting period (the common unit price at IPO less the present value of the expected distributions) plus the present value of the expected distributions for any tranches that vest). We recognize this total as compensation expense ratably over the requisite service period for each tranche. The probable outcome of each performance condition will be reassessed at each reporting period and changes will be recorded as a cumulative catch-up adjustment to equity-based compensation expense. The use of alternate judgments and assumptions could result in the recognition of different levels of equity-based incentive compensation costs.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Our exposure to market risks primarily arise from changes in interest rates and foreign currency exchange rates. We do not take title to the crude oil, biofuels or related products that we handle at our facilities and as a result we have minimal direct exposure to risks associated with changes in commodity prices. All of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or foreign exchange rates.

Interest Rate Risk

Our credit agreement includes a variable interest rate component that exposes us to fluctuations in interest rates. Interest rates prevalent in the current credit markets have been and remain at historical lows. Our credit agreement allows us the option of selecting interest rates on our borrowings that are based upon the London Interbank Offered Rate ("LIBOR"), the Canadian Dealer Offered Rate ("CDOR"), and a U.S. interest rate as set forth in the credit agreement. As the economic environment in North America and Europe strengthens, monetary policy could tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing our financing costs to increase accordingly. We may use derivative instruments to hedge our exposure to variable interest rates in the future. Our current exposure to interest rate fluctuations relates to the approximate $81.4 million of our outstanding indebtedness maturing in 2019 bearing interest at a 3.873% variable rate at December 31, 2014. Due to the frequent repricing of the underlying interest rates on amounts outstanding under our Credit Agreement, the fair value approximates the carrying value of our outstanding indebtedness.

Foreign Currency Risk

Our cash flow related to our Hardisty rail terminal is reported in the U.S. dollar equivalent of such amounts as denominated in Canadian dollars. Monetary assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.

A majority of the cash flows we produce are derived from our Hardisty rail terminal operations in the province of Alberta, Canada. As a result fluctuations in the exchange rates between the Canadian dollar and the U.S. dollar could have a significant effect on our results of operations, cash flows and financial position. The quarterly cash distributions we expect to make to our unitholders will be denominated in U.S. dollars, which are supported by cash distributions we receive from our foreign and domestic subsidiaries. As such, a portion of the cash flow we expect to distribute will be subject to currency exchange rate fluctuations between U.S. dollars and Canadian dollars. For example, if the

75

Canadian dollar weakens significantly relative to the U.S. dollar, the distributions we receive from our Canadian subsidiaries in U.S. dollars could reduce the amount of cash we have available to distribute to our unitholders.

We use derivative financial instruments to minimize the impact of changes in currency exchange rates, including options, swaps and forward contracts. In May 2014, we entered into collar arrangements with a notional value of $37.2 million CAD, on the date executed, which uses put and call options to limit the amount of loss or gain that we will receive upon converting the notional value to U.S. dollars. These put and call options pertain to the three month periods ending December 31, 2014, March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. The collar was executed to secure $37.2 million CAD at an exchange rate range of between 0.91 and 0.93 U.S. dollars to 1.00 Canadian dollars. We have not designated these derivative financial instruments as hedges of our foreign currency rate exposures, but instead we mark these contracts to market value quarterly with the change in fair value recorded to "Gain associated with derivative instruments" in our consolidated statements of operations. The gains or losses associated with changes in the fair value of our foreign currency derivative contracts do not affect our cash flows until the underlying contract is settled by making or receiving a payment to or from the counterparty.

The following table presents summarized information about our outstanding foreign currency options at December 31, 2014:

	Notional (CAD)		Strike Price (1)	Market Price (1)
Portion of option contracts maturing in 2015
Puts (purchased)	$	29,722,200	0.9100	0.8606
Calls (written)	$	29,722,200	0.9300	0.8606

(1) Strike and market prices are denoted in CAD/USD.

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Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS,

SUPPLEMENTARY INFORMATION AND

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

USD PARTNERS LP

	Page
Reports of Independent Registered Public Accounting Firms	78
Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012	80
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014, 2013 and 2012	81
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	82
Consolidated Balance Sheets as of December 31, 2014 and 2013	83
Consolidated Statements of Partners’ Capital for the years ended December 31, 2014, 2013 and 2012	83
Notes to the Consolidated Financial Statements	84

FINANCIAL STATEMENT SCHEDULES

Financial statement schedules not included in this report have been omitted because they are not applicable or the required information is either immaterial or shown in the consolidated financial statements or notes thereto.

77

Report of Independent Registered Public Accounting Firm

Board of Directors of USD Partners GP LLC, as General Partner of USD Partners LP and the Partners of

USD Partners LP

Houston, Texas

We have audited the accompanying consolidated balance sheet of USD Partners LP and its subsidiaries (the “Partnership”) as of December 31, 2014, and the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership at December 31, 2014, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Houston, Texas

March 30, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the General Partner of

USD Partners LP

We have audited the accompanying consolidated balance sheet of the predecessor to USD Partners LP (the “Predecessor”) as of December 31, 2013, and the related consolidated statements of operations, comprehensive income (loss), cash flows and partners’ capital for each of the two years in the period ended December 31, 2013. These consolidated financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Predecessor is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor as of December 31, 2013, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Farmington Hills, Michigan

July 18, 2014, except with respect to Note 3, as to which the date is March 30, 2015

79

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2014			2013			2012
	(in thousands, except per unit amounts)
Revenues:
Terminalling services	$	18,266		$	7,130		$	8,703
Terminalling services - related party	3,499			—			—
Railroad incentives	719			—			—
Fleet leases	8,788			13,572			15,964
Fleet services	720			235			5
Fleet services — related party	1,501			962			—
Freight and other reimbursables	2,141			1,778			203
Freight and other reimbursables — related party	464			2,624			—
Total revenues	36,098			26,301			24,875
Operating costs:
Subcontracted rail services	6,994			1,898			1,847
Pipeline fees	3,625			—			—
Fleet leases	8,788			13,572			15,964
Freight and other reimbursables	2,605			4,402			203
Selling, general and administrative	6,905			1,475			2,080
Selling, general and administrative — related party	3,903			2,983			1,160
Depreciation	2,631			502			490
Total 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			—
Income (loss) from continuing operations before provision for income taxes	(7,492		)	(1,811		)	1,081
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 of discontinued operations	—			7,295			394,318
Net income (loss)	$	(7,678	)	$	6,402		$	460,577
Less: Predecessor loss prior to the initial public offering (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 initial public offering (from October 15, 2014 through December 31, 2014)	$	(472	)
Net income (loss) attributable to limited partner interest:
Income (loss) from continuing operations	$	(7,524	)	$	(1,805	)	$	1,034
Income from discontinued operations	—			8,079			450,332
Net income (loss) attributable to limited partner interest	$	(7,524	)	$	6,274		$	451,366
Basic and diluted earnings per common unit (see note 3):
Income (loss) from continuing operations	$	(0.29	)	$	(0.16	)	$	0.09
Income from discontinued operations	—			0.70			38.97
Net income (loss) per common unit (basic and diluted)	$	(0.29	)	$	0.54		$	39.06
Weighted average common units outstanding	3,042			1,094			1,094
Basic and diluted earnings per subordinated unit (see note 3):
Income (loss) from continuing operations	$	(0.63	)	$	(0.16	)	$	0.09
Income from discontinued operations	—			0.70			38.97
Net income (loss) per subordinated unit (basic and diluted)	$	(0.63	)	$	0.54		$	39.06
Weighted average subordinated units outstanding	10,464			10,464			10,464

The accompanying notes are an integral part of these consolidated financial statements.

80

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	For the Years Ended December 31,
	2014			2013			2012
	(in thousands)
Net income (loss)	$	(7,678	)	$	6,402		$	460,577
Other comprehensive income (loss) — foreign currency translation, net of income tax expense (benefit) of $667 thousand, $(719) thousand and $(3) thousand	1,295			(1,395		)	(5		)
Comprehensive income (loss)	$	(6,383	)	$	5,007		$	460,572

The accompanying notes are an integral part of these consolidated financial statements.

81

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2014			2013			2012
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(7,678	)	$	6,402		$	460,577
Income from discontinued operations	—			(948		)	(65,204		)
Gain on sale of discontinued operations	—			(7,295		)	(394,318		)
Income (loss) from continuing operations	(7,678		)	(1,841		)	1,055
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
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 operating assets and liabilities:
Accounts receivable	(4,264		)	(602		)	(1,019		)
Accounts receivable — related party	268			(402		)	—
Prepaid rent	(726		)	(2,761		)	(2,500		)
Prepaid expenses and other current assets	(3,789		)	(1,892		)	—
Accounts payable and accrued expenses	(2,372		)	6,590			1,888
Deferred revenue and other liabilities	17,497			7,263			668
Deferred revenue — related party	—			962			—
Change in restricted cash	(6,490		)	—			—
Net cash provided by (used in) operating activities	(3,085		)	9,239			1,798
Cash flows from investing activities:
Additions of property and equipment	(33,736		)	(56,114		)	(773		)
Purchase of derivative instruments	(468		)	—			—
Net cash used in investing activities	(34,204		)	(56,114		)	(773		)
Cash flows from financing activities:
Payments on BOK credit facility	(97,845		)	—			(15,668		)
Proceeds from borrowings on BOK credit facility	67,845			—			—
Payments for deferred financing costs	(3,909		)	(261		)	(926		)
Contributions from parent	14,329			—			—
Distributions to parent	(107,828		)	(7,547		)	(8,899		)
Proceeds from Term Loan Facility	100,000			—			—
Repayment of Term Loan Facility	(14,992		)	—			—
Net proceeds from the initial public offering	137,495			—			—
(Repayment) proceeds of loan from parent	(49,390		)	52,693			266
Net cash provided by (used in) financing activities	45,705			44,885			(25,227		)
Cash provided by discontinued operations:
Net cash provided by operating activities	—			3,411			52,331
Net cash provided by investing activities	29,473			10,000			436,762
Net cash used in financing activities	(5,232		)	(8,243		)	(463,406		)
Net cash provided by discontinued operations	24,241			5,168			25,687
Effect of exchange rates on cash	1,441			(1,498		)	(5		)
Net change in cash and cash equivalents	34,098			1,680			1,480
Cash and cash equivalents — beginning of year	6,151			4,471			2,991
Cash and cash equivalents — end of year	$	40,249		$	6,151		$	4,471

The accompanying notes are an integral part of these consolidated financial statements.

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USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2014			2013
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	40,249		$	6,151
Restricted cash	6,490			—
Accounts receivable, net	4,221			1,587
Accounts receivable — related party	134			402
Prepaid rent, current portion	3,229			983
Prepaid expenses and other current assets	7,141			1,977
Note receivable — related party	2,472			—
Current assets — discontinued operations	—			30,076
Total current assets	63,936			41,176
Property and equipment, net	84,059			61,364
Prepaid rent, net of current portion	2,757			4,278
Deferred financing costs, net	2,900			450
Total assets	$	153,652		$	107,268
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,875		$	7,073
Accounts payable — related party	492			—
Loan from parent	—			50,991
Deferred revenue, current portion	15,540			1,563
Deferred revenue, current portion — related party	5,256			—
Other current liabilities	877			3,656
Current liabilities — discontinued operations	—			5,835
Total current liabilities	26,040			69,118
Credit facility	81,358			30,000
Deferred revenue, net of current portion	3,656			4,585
Deferred revenue — related party, net of current portion	1,931			962
Total Liabilities	112,985			104,665
Commitments and contingencies (Note 10)
Partners’ capital
Predecessor partner interest	—			4,003
Common units (10,213,545 authorized and issued at December 31, 2014)	128,097			––
Class A units (220,000 authorized and issued at December 31, 2014)	550			––
Subordinated units (10,463,545 authorized and issued at December 31, 2014)	(87,978		)	––
General partner units (427,083 authorized and issued at December 31, 2014)	103			—
Accumulated other comprehensive loss	(105		)	(1,400		)
Total partners' capital	40,667			2,603
Total liabilities and partners' capital	$	153,652		$	107,268

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	For the Years Ended December 31,
	2014					2013				2012
	Units		Amount			Units	Amount			Units	Amount
	(in thousands, except unit amounts)
Common units:
Beginning balance	—		$	—		—	$	—		—	$	—
Allocation of partnership interests	1,093,545		292			—	—			—	—
Proceeds from IPO	9,120,000		137,495			—	—			—	—
Net loss allocation from October 15 through December 31, 2014	—		(228		)	—	—			—	—
Distributions	—		(9,462		)	—	—			—	—
Ending balance	10,213,545		128,097			—	—			—	—
Class A units:
Beginning balance	—		—			—	—			—	—
Units issued	250,000		—			—	—			—	—
Unit based compensation expense	—		550			—	—			—	—
Forfeited units	(30,000	)	—			—	—			—	—
Distributions	—		—			—	—			—	—
Ending balance	220,000		550			—	—			—	—
Subordinated units:
Beginning balance	—		—			—	—			—	—
Allocation of partnership interests	10,463,545		2,794			—	—			—	—
Net loss allocation from October 15 through December 31, 2014	—		(234		)	—	—			—	—
Distributions	—		(90,538		)	—	—			—	—
Ending balance	10,463,545		(87,978		)	—	—			—	—
General Partner:
Beginning balance	—		—			—	—			—	—
Allocation of partnership interests	427,083		113			—	—			—	—
Net loss allocation from October 15 through December 31, 2014	—		(10		)	—	—			—	—
Distributions	—		—			—	—			—	—
Ending balance	427,083		103			—	—			—	—
Predecessor Partner Interest:
Beginning balance			4,003				13,391				25,119
Net Income			—				6,402				460,577
Net loss for the period January 1 through October 14, 2014			(7,206		)		—				—
Contribution			14,233				—				—
Distributions			(7,831		)		(15,790		)		(472,305		)
Allocation of partnership interests			(3,199		)		—				—
Ending balance			—				4,003				13,391
Accumulated other comprehensive income (loss):
Beginning balance			(1,400		)		(5		)		—
Cumulative translation adjustment			1,295				(1,395		)		(5		)
Ending balance			(105		)		(1,400		)		(5		)
Total partners’ capital at December 31,			$	40,667			$	2,603			$	13,386

The accompanying notes are an integral part of these consolidated financial statements.

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USD PARTNERS LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Initial Public Offering

USD Partners LP and its consolidated subsidiaries, which are referred to herein as "we," "our," "us," "USDP" and the "Partnership," is a Delaware limited partnership organized on June 5, 2014 by US Development Group LLC ("USD") and USD Partners GP LLC, our general partner. Subsequently, USD contributed all of its ownership interests in USD Partners GP LLC to its wholly-owned subsidiary USD Group LLC ("USDG").

In contemplation of the initial public offering ("IPO"), of our common units, the board of directors of our general partner granted 250,000 Class A units, representing limited partner interests in USDP, to key employees in August 2014. The awards issued are performance-based awards that contain distribution equivalent rights. We determined the grant date of these awards, as defined within the relevant accounting guidance, to be the day on which the IPO was effective, or October 8, 2014. Assuming certain conditions are met, Class A units become eligible to convert into common units in four equal tranches beginning no earlier than January 1, 2016 at a conversion factor ranging from 1.0 to 2.0.

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 senior secured credit agreement with a consortium of lenders with an aggregate capacity of $300 million comprised of a $200 million revolving credit component and a $100 million term loan component. 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 USDG 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 USDG the right to receive $100 million. Additionally, we issued to 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 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 senior secured credit agreement, which we used to distribute to USDG pursuant to the right we granted them in connection with our IPO. We also received a debt guarantee whereby USDG will repay up to $100 million of any amounts outstanding under the term loan component of our senior secured credit agreement upon default by us.

Unless the context otherwise requires, references in this 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 the Partnership in connection with our IPO of 9,120,000 common units that we completed on October 15, 2014: San Antonio Rail Terminal LLC (“SART”), USD Logistics Operations GP LLC, USD Logistics Operations LP, USD Rail LP, USD Rail Canada ULC, USD Terminals Canada ULC, West Colton Rail Terminal LLC ("WCRT"), USD Terminals International, and USD Rail International, collectively, the “Contributed Subsidiaries.” The Predecessor also includes the

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membership interests in the following five subsidiaries of USD which operated crude oil rail terminals that were sold in December 2012 (the "Sale") to a large energy transportation, terminalling and pipeline company (the "Acquirer"): 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.” As a result of the sale, another subsidiary, USD Services LLC ("USDS"), ceased operations and is also included in the results of Discontinued Operations. Refer to Note 17 - Discontinued Operations for additional details. References to USDP, the Partnership, 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.

General

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. We generate the majority of our revenue and cash flows by charging fixed fees for providing terminalling services such as railcar loading and unloading for bulk liquid products including crude oil, biofuels, and related products. We also provide railcar services through the management of a railcar fleet that is committed to customers on a long-term basis. 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. Since we do not own any of the crude oil or refined petroleum products that we handle and do not engage in the trading of crude oil or refined petroleum products, we have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long-term.

From the time of our formation in June 2014 our capital accounts consisted of a 2.0% general partner interests held by USD Partners GP LLC, a wholly-owned subsidiary of USD Group LLC that held all of our limited partner interests. At December 31, 2013 the capital accounts of our subsidiaries were wholly-owned by USD Group LLC.

At December 31, 2014, our capital accounts were distributed as follows:

	2014
Common units held by the Public	42.8	%
Common units held by USDG	5.1	%
Subordinated units held by USDG	49.1	%
Class A units held by management	1.0	%
General partner interest held by USD Partners GP LLC	2.0	%
	100.0	%

US Development Group LLC

USD is a growth-oriented developer, builder, operator and manager of energy-related infrastructure with a primary focus on development of the hydrocarbons-by-rail concept. USD has developed, built, operated and sold a number of unit train-capable origination and destination terminals. USD is the indirect owner of USD Group LLC and our general partner and is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD's management team members.

Business Operations

Our principal operations consist of entities that operate terminal facilities for liquid hydrocarbon and petroleum based products and provide rail and fleet logistics and railcar fleet leasing services. We generate a majority of our revenue and cash flows by providing terminalling services such as railcar loading and unloading for bulk liquid products including crude oil, biofuels, and related products. We do not own any of the crude oil or refined petroleum products that we handle and do not engage in the trading of crude oil or refined petroleum products. Our Terminalling services and Fleet services businesses are discussed below and the financial information associated with these operations are presented in Note 11. Segment Reporting.

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Prior to the completion of our IPO on October 15, 2014, our financial position, results of operations and cash flows consisted of the Predecessor, which represented a combined reporting entity. Subsequent to the IPO, our financial position, results of operations and cash flows consist of consolidated USDP activities and balances. The assets and liabilities in our consolidated financial statements have been reflected on a historical cost basis, as prior to the IPO all of the assets and liabilities presented were wholly-owned by USDG and its affiliates and were transferred within the USDG consolidated group.

The consolidated statements of operations for periods prior to the IPO included expense allocations for certain corporate functions historically provided by USDG, including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, communications, insurance, utilities and executive compensation. Those allocations were based primarily on direct usage when identifiable, budgeted volumes or projected revenues, the remainder allocated evenly across the number of operating entities. The consolidated statements of operations for periods prior to the IPO include amounts allocated to the Predecessor for general corporate expenses incurred by USDG within "Selling, general and administrative ". Management considers the basis on which the expenses have been allocated to reasonably reflect the utilization of services provided to or for the benefit received by the Predecessor during the periods presented prior to the IPO. The allocations may not, however, reflect the expenses the Predecessor would have incurred as an independent company for the periods presented prior to the IPO. Actual costs that may have been incurred if the Predecessor had been a standalone entity would depend on a number of factors, including the organizational structure, whether functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure. The Predecessor is unable to determine what such costs would have been had the Predecessor been independent prior to the IPO. Effective with the IPO, our general partner and its affiliates provide services to us pursuant to an omnibus agreement and a service agreement between the parties. The allocations and related estimates and assumptions are described more fully in Note 7 — Transactions with Related Parties.

Comparative Amounts

We have made certain reclassifications to the amounts reported in prior years to conform with the current year presentation. None of these reclassifications have an impact on our operating results, cash flows or financial position.

Use of Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, or U.S. GAAP. Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known. Significant estimates we make include the estimated lives of depreciable property and equipment, recoverability of long-lived assets, and the allowance for doubtful accounts.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. We

consolidate the accounts of entities over which we have a controlling financial interest through our ownership of the general partner or the majority voting interests of the entity.

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We periodically assess the financial condition of the financial institutions where these funds are held and believe that our credit risk is minimal.

Restricted Cash

We include in restricted cash on our consolidated balance sheets, amounts representing a cash account for which the use of funds is restricted by the collaborative agreement we entered in 2014 with Gibson Energy Partnership (“Gibson”). The collaborative arrangement is further discussed in Note 9. Collaborative Arrangements. As of December 31, 2014 we had a restricted cash balance of $6.5 million representing undistributed amounts retained in our joint revenue collection bank account.

Accounts Receivable

Accounts receivable are primarily due from our customers, which include oil producing and petroleum refining companies, as well as marketers of petroleum, petroleum products and biofuels, for services we have provided. We perform ongoing credit evaluations of our customers. When appropriate, we use the specific identification method to estimate allowances for doubtful accounts based on our customers’ financial condition and collection history, and other pertinent factors. Accounts are written-off against the allowance when significantly past due and deemed uncollectible by management. We had an allowance for doubtful accounts of approximately $24.5 thousand at December 31, 2014, and $0 at December 31, 2013. We recognized bad debt expense of approximately $1.4 million for the year ended December 31, 2014 and $0 for both of the years ended December 31, 2013 and 2012, which is included in "Selling, general and administrative" in our consolidated statements of operations.

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense using the effective interest method over the life of the related debt.

Capitalization Policies and Depreciation Methods

We record property and equipment at its original cost, which we depreciate on a straight-line basis over the estimated useful lives of the assets that range from five to 20 years. Our determination of the useful lives of property and equipment requires us to make various assumptions when the assets are placed into service about the expected usage, normal wear and tear and the extent and frequency of maintenance programs. Expenditures for repairs and maintenance are charged to expense as incurred, while improvements that extend the service life or capacity of existing property and equipment are capitalized. Upon the sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized in the results of operations.

During construction we capitalize direct costs, such as labor, materials and overhead, as well as interest cost we may incur on indebtedness at our incremental borrowing rate.

Impairment of Long-lived Assets

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. We consider a long-lived asset to be impaired when the sum of the estimated, undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset. Factors that indicate potential impairment include a significant decrease in the fair value of the asset, operating or cash flow losses associated with the use of the asset and a significant change in the asset’s physical condition or use. Our estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence when alternative courses of action to recover the carrying amount of a long-lived asset are under consideration. We recognize an impairment loss to the extent the carrying value exceeds the estimated fair

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value of the long-lived asset following our determination that the carrying amount of a long-lived asset is not recoverable based on the estimated future undiscounted cash flows. We determined there were no asset impairment indicators in 2014, 2013 and 2012.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value to our financial instruments and related disclosures, which include cash and cash equivalents, accounts receivable, accounts payable, debt, and derivative instruments. We define fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs, summarized as follows:

• Level 1 — Quoted prices in active markets for identical assets or liabilities.

• Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities).

• Level 3 — Significant unobservable inputs (including the Predecessor’s own assumptions in determining fair value).

We use the cost, income or market valuation approach to estimate the fair value of our assets and liabilities when insufficient market-observable data is available to support our valuation assumptions.

The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, and our credit facility as presented on our consolidated balance sheets approximate fair value due to the short-term nature of these items and with respect to the credit facility, the frequent re-pricing of the underlying obligations. The fair value of our historical accounts receivable with affiliates and payables with affiliates cannot be determined due to the related party nature of these items.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in foreign currency exchange rates. At December 31, 2014, we do not employ any derivative financial instruments to manage our exposure to fluctuations in interest rates, although we intend to use derivative financial instruments, including swaps, options and other financial instruments with similar characteristics to manage this exposure in the future. In order to manage our exposure to fluctuations in foreign currency exchange rates and the related risks to our unitholders, we use derivative financial instruments to offset these risks. We have a program that primarily utilizes foreign currency collar derivative contracts, representing written call options and purchased put options, to reduce the risks associated with the effects of foreign currency exposures related to our Canadian subsidiaries which have cash flows denominated in Canadian dollars (“CAD”). Under this program, our strategy is to have gains or losses on the derivative contracts mitigate the foreign currency transaction gains or losses to the extent practical. Economically, the collars help us to limit our exposure such that the exchange rate will effectively lie between the floor and the ceiling rates set forth in the derivative contacts. All of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into for speculative purposes.

In accordance with the authoritative accounting guidance, we record all derivative financial instruments in our consolidated balance sheets at fair value as current or noncurrent assets or liabilities on a net basis by counterparty. We do not designate, nor have we historically designated, any of our derivative financial instruments as hedges of an underlying asset, liability and/or forecasted transaction. To qualify for hedge accounting treatment as set forth in the

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authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation. As a result, changes in the fair value of our derivative financial instruments and the related cash settlement of matured contracts are recognized in "Gain associated with derivative instruments" on our consolidated statements of operations.

Unit Based Compensation

In connection with our IPO and as provided for in our partnership agreement, we granted non-voting Class A units to certain executive officers and other key employees of our general partner who provide services to us. We determined the fair value of our Class A units based on the market price of the underlying common units on the date of our IPO, adjusted for vesting probabilities associated with performance-based vesting requirements and the present value of the expected distributions. The ultimate percentage of units vesting in each tranche depends on a performance condition: specifically, the distributions paid in the last year of the vesting period for each tranche. If distributions meet or fall below a threshold, the Class A units in that tranche are forfeited. If distributions exceed a threshold by less than a target amount, the Class A units in that tranche vest and become convertible into one common unit. If distributions exceed the threshold by more than the target amount, the Class A units in that tranche vest and become convertible into more than one common unit (1.25 to 2.0 times common units per Class A unit, depending on the tranche). Distributions over the vesting period are not paid in arrearage if the Class A units become convertible into more than one common unit. we estimated the expense for each tranche as the number of unit equity awards, multiplied by the per unit grant date fair value of those awards less estimated forfeitures in the probable vesting scenario for each tranche (equaling the applicable conversion multiple times the value of the stock excluding the expected distributions paid over the vesting period (the common unit price at IPO less the present value of the expected distributions) plus the present value of the expected distributions for any tranches that vest). The estimated fair value of our Class A units is amortized over the four-year vesting period using the straight-line method. The Class A units awards will convert into our common units upon the vesting.

Revenue Recognition

We derive our revenues from railcar loading and unloading services for bulk liquid products, including crude oil, biofuels, and related products, as well as sourcing railcar fleets and related logistics and maintenance services. We recognize revenue when persuasive evidence of an arrangement exists, delivery has occurred or services have been performed, the buyer’s price is fixed or determinable and collectability is reasonably assured. In accordance with the applicable accounting guidance, we record revenues for fleet leases on a gross basis, since we are deemed the primary obligor for the services. We also recognize as revenue on our consolidated statements of operations in "Freight and other reimbursables," on a gross basis, the amounts we charge to our customers for the out-of-pocket expenses we have incurred to provide our railcar fleet services.

We recognize terminalling services revenue when services are provided based on the contractual rates set forth in our agreements related to throughput volumes. Substantially all of the capacity at our Hardisty rail terminal is contracted under multi-year agreements that contain “take-or-pay” provisions where we are entitled to payment from our customer of a minimum monthly commitment fee, regardless of whether the specified throughput to which the customer committed is achieved. These agreements grant the customers make-up rights that allow them to load volumes in excess of their minimum monthly commitment in future periods, without additional charge, to the extent capacity is available for the excess volume. The make-up rights typically expire, if unused, in subsequent periods up to six months following the period for which the volumes were originally committed. We defer recognition of the revenue associated with volumes that are below the minimum monthly commitments until the earlier of (1) the throughput is utilized, (2) the customer’s ability to make up the minimum volume has expired in accordance with the terms of the agreements, or (3) we determine that the likelihood that the customer will be able to make up the minimum volume is remote. Revenue for fleet leases and related party administrative services is recognized ratably over the contract period. Revenue for reimbursable costs is recognized as the costs are incurred. We have deferred revenues for amounts collected from customers in our Fleet services segment, which will be recognized as revenue when earned pursuant to the terms of our contracts. We have prepaid rent associated with these deferred revenues on our railcar leases, which we will recognize as expense as these railcars are used.

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On December 13, 2013, USDTC entered into a binding agreement with a major railway transportation company, which we refer to as the "Railway," effective with the commencement of the Hardisty rail terminal in June 2014, whereby in consideration for the Railway being the sole rail freight transportation service provider at the Hardisty rail terminal for certain customers, the Railway agreed to pay USDTC an average incentive payment amount of $100 CAD per railcar shipped up to a maximum of $12.5 million CAD through mid-2017. We recognize these revenues in "Railroad incentives" in our consolidated statements of operations as railcars utilize the services of the Railway pursuant to the terms of the agreement.

Income Taxes

We are not a taxable entity for United States federal income tax purposes, or for a majority of the states that impose an income tax. Taxes on our net income are generally borne by our unitholders through the allocation of taxable income, except for USD Rail LP which, on October 7, 2014, elected to be classified as an entity taxable as a corporation. Our income tax expense partially results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in the authoritative accounting guidance. Our current and historical provision for income taxes also reflects income taxes associated with USD Rail LP and our Canadian operations.

We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax assets and liabilities in the period the legislation is enacted.

Pursuant to the authoritative accounting guidance regarding uncertain tax positions, we recognize the tax effects of any uncertain tax position as the largest amount that will more likely than not be realized upon ultimate settlement with the taxing authority having full knowledge of the position and all relevant facts. Under this criterion, we evaluate the most likely resolution of an uncertain tax position based on its technical merits and on the outcome that we expect would likely be sustained under examination.

Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.

Foreign Currency

The functional currency for our Canadian operations is the Canadian dollar. We translate the results of operations for our foreign subsidiaries from their local currencies to the U.S. dollar using average exchange rates during the period, while we translate assets and liabilities at the exchange rate in effect on the reporting date. We report the cumulative amount of gains and losses resulting from translating foreign currency financial statements in "Accumulated other comprehensive income," which is shown as a separate component of Partners' Capital on our consolidated balance sheets. Cumulative translation adjustments, representing losses, as of December 31, 2014 and 2013 were $105 thousand and $1.4 million, respectively. Foreign currency transaction losses related to the years ended December 31, 2014, 2013 and 2012 were $4.9 million, $39 thousand and $0, respectively, and are included in "Foreign currency transaction loss" on our consolidated statements of operations.

Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time an asset is constructed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the expected costs as part of the carrying value of the related assets. We recognize any ongoing expense for the accretion component of the liability resulting from changes in value of the ARO due to the passage of time as part of accretion expense. We depreciate the

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initial capitalized cost over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

Legal obligations exist for our SART and WCRT facilities due to terms within our lease agreements with the lessor that require us to remove our facilities at final abandonment. We own the land on which our Hardisty rail terminal and related facilities reside and as a result, similar legal obligations do not exist that would require us to remove our Hardisty rail facilities at final abandonment. Sufficient data exists to estimate the cost of abandoning or retiring our SART and WCRT facilities. However, insufficient information exists to reasonably determine the timing and/or method of settlement for estimating the fair value of the ARO. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions or the estimated economic life of the asset. Useful lives of our terminal facilities are primarily derived from available supply resources and ultimate consumption of those resources by end users. Many variables can affect the remaining lives of the assets, which preclude us from making a reasonable estimate of the ARO. We will recognize the fair value of an ARO for each of these facilities in the period in which sufficient information exists that will allow us to reasonably estimate potential settlement dates and methods. We do not have any ARO liabilities recorded at December 31, 2014 and 2013.

Recent Accounting Pronouncements Not Yet Adopted

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.

Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern

In August 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-15 which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016, with early adoption permitted. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.

Reporting Discontinued Operations and Disclosure of Disposals

In April 2014, the FASB, issued Accounting Standards Update No. 2014-08 that changes the criteria and requires expanded disclosures for reporting discontinued operations. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively. We do not expect that the adoption of this pronouncement will have a material impact on our consolidated financial statements.

3. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

We allocate our net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income,

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to our limited partners, our general partner and holder of our incentive distribution rights ("IDRs"), in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our general partner and the holders of the IDRs in accordance with the terms of our partnership agreement based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.

Distribution Targets	Portion of Quarterly Distribution Per Unit	Percentage Distributed to Limited Partners	Percentage Distributed to General Partner (including IDRs)
Minimum Quarterly Distribution	Up to $0.2875	98%	2%
First Target Distribution	> $0.2875 to $0.330625	98%	2%
Second Target Distribution	> $0.330625 to $0.359375	85%	15%
Third Target Distribution	> $0.359375to $0.431250	75%	25%
Over Third Target Distribution	In excess of $0.431250	50%	50%

We determined basic and diluted net income (loss) per limited partner unit as as set forth in the following tables:

	For the Year Ended December 31, 2014
	Limited Partner Common Units			Limited Partner Subordinated Units USDG			Class A Units Management			General Partner USD Partners GP LLC			Total
	(in thousands, except unit and per unit amounts)
Predecessor net loss allocation to general and limited partner interests	$	(668	)	$	(6,394	)	$	—		$	(144	)	$	(7,206	)
Net loss attributable to general and limited partner interests in USD Partners LP	(228		)	(234		)	—			(10		)	(472		)
Distributable earnings (1)	3,499			12,033			61			318			15,911
Distributions in excess of earnings	$	(4,395	)	$	(18,661	)	$	(61	)	$	(472	)	$	(23,589	)
Weighted average units outstanding(2)	3,042,477			10,463,545			53,425			427,083
Distributable earnings per unit (3)	$	1.15		$	1.15		$	1.14
Overdistributed earnings per unit (4)	(1.44		)	(1.78		)	(1.14		)
Net loss per limited partner (basic and diluted)	$	(0.29	)	$	(0.63	)	$	—

(1) Represents the distributions that would have been paid during the year assuming the minimum quarterly distribution amount of $0.2875 per unit, or $1.15 per unit on an annualized basis, was distributed based on a retrospective basis as if the units issued to our general partner and USDG were outstanding the entire period and the common units issued to the public and Class A units issued to certain members of management were were outstanding from October 15, 2014, the date of the IPO.

(2) Represents the weighted average units outstanding computed on a retrospective basis as if the units issued to our general partner and USDG in connection with the IPO were outstanding for the entire year and the common units issued to the public and Class A units were outstanding from the October 15, 2014 closing of the IPO transaction.

(3) Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.

(4) Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.

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	For the Year Ended December 31, 2013
	Limited Partner Common Units			Limited Partner Subordinated Units USDG			Class A Units Management		General Partner USD Partners GP LLC			Total
	(in thousands, except unit and per unit amounts)
Net income attributable to general and limited partner interests	$	594		$	5,680		$	—	$	128		$	6,402
Less: Income from discontinued operations attributable to general and limited partner interests	765			7,314			—		164			8,243
Income from continuing operations attributable to general and limited partner interests	(171		)	(1,634		)	—		(36		)	(1,841		)
Distributable earnings (1)	1,258			12,033			—		271			13,562
Distributions in excess of earnings	$	(1,429	)	$	(13,667	)	$	—	$	(307	)	$	(15,403	)
Weighted average units outstanding (2)	1,093,545			10,463,545			—		427,083
Distributable earnings per unit (3)	$	1.15		$	1.15		$	—
Overdistributed earnings per unit (4)	(1.31		)	(1.31		)	—
Net loss per limited partner unit from continuing operations (basic and diluted)	$	(0.16	)	$	(0.16	)	$	—
Net income per limited partner unit from discontinued operations (basic and diluted)	0.7			0.7			—
Net income per limited partner unit (basic and diluted)	$	0.54		$	0.54		$	—

(1) Represents the distributions that would have been paid during the year assuming the minimum quarterly distribution amount of $0.2875 per unit, or $1.15 per unit on an annualized basis, was distributed based on a retrospective basis as if the units issued to our general partner and USDG were outstanding the entire period and the common units issued to the public and Class A units issued to certain members of management were were outstanding from October 15, 2014, the date of the IPO.

(2) Represents the weighted average units outstanding computed on a retrospective basis as if the units issued to our general partner and USDG in connection with the IPO were outstanding for the entire year and the common units issued to the public and Class A units were outstanding from the October 15, 2014 closing of the IPO transaction.

(3) Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.

(4) Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.

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	For the Year Ended December 31, 2012
	Limited Partner Common Units			Limited Partner Subordinated Units USDG			Class A Units Management		General Partner USD Partners GP LLC			Total
	(in thousands, except unit and per unit amounts)
Net income attributable to general and limited partner interests	$	42,709		$	408,657		$	—	$	9,211		460,577
Less: Income from discontinued operations attributable to general and limited partner interests	42,611			407,721			—		9,190			459,522
Income from continuing operations attributable to general and limited partner interests	98			936			—		21			1,055
Distributable earnings (1)	1,258			12,033			—		271			13,562
Distributions in excess of earnings	$	(1,160	)	$	(11,097	)	$	—	$	(250	)	$	(12,507	)
Weighted average units outstanding (2)	1,093,545			10,463,545			—		427,083
Distributable earnings per unit (3)	$	1.15		$	1.15		$	—
Overdistributed earnings per unit (4)	(1.06		)	(1.06		)	—
Net income per limited partner unit from continuing operations (basic and diluted)	$	0.09		$	0.09		$	—
Net income per limited partner unit from discontinued operations (basic and diluted)	38.97			38.97			—
Net income per limited partner unit (basic and diluted)	$	39.06		$	39.06		$	—

(1) Represents the distributions that would have been paid during the year assuming the minimum quarterly distribution amount of $0.2875 per unit, or $1.15 per unit on an annualized basis, was distributed based on a retrospective basis as if the units issued to our general partner and USDG were outstanding the entire period and the common units issued to the public and Class A units issued to certain members of management were were outstanding from October 15, 2014, the date of the IPO.

(2) Represents the weighted average units outstanding computed on a retrospective basis as if the units issued to our general partner and USDG in connection with the IPO were outstanding for the entire year and the common units issued to the public and Class A units were outstanding from the October 15, 2014 closing of the IPO transaction.

(3) Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.

(4) Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.

4. PROPERTY AND EQUIPMENT

Our property and equipment is comprised of the following:

	As of December 31,						EstimatedUseful  Lives(Years)
	2014			2013
	(in thousands)
Land	$	3,279		$	6,148		N/A
Trackage and facilities	78,938			8,007			20
Equipment	5,611			488			5-10
Furniture	51			5			5
Total property and equipment	87,879			14,648
Accumulated depreciation	(4,326		)	(1,803		)
Construction in progress	506			48,519
Property and equipment, net	$	84,059		$	61,364

The cost of property and equipment classified as “Construction in progress” is excluded from costs being depreciated. These amounts represent property that was not yet ready to be placed into productive service as of the respective balance sheet date.

Capitalized interest for the year ended December 31, 2014, was $230 thousand and $0 for the years ended December 31, 2013 and 2012.

5. DEBT

Credit Agreement

In connection with our IPO, we entered into a five-year, $300 million senior secured credit agreement (the "Credit Agreement") comprised of a $200 million revolving credit facility (the "Revolving Credit Facility") and a $100 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.

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

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prime rate, in each case, plus an applicable margin. Our borrowings under the Credit Facility 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 Facility. The actual interest rate was 3.873% at December 31, 2014.

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 Facility 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;

• Consolidated Total Leverage Ratio of not greater than 4.50 to 1.00 (or 5.00 to 1.00 at any time after we have issued at least $150.0 million of unsecured notes). In addition, upon the consummation of a Material Acquisition (as defined in our Credit Facility), for the fiscal quarter in which the Material Acquisition is consummated and for two fiscal quarters immediately following such fiscal quarter (the “Material Acquisition Period”), if elected by us by written notice to the Administrative Agent given on or prior to the date of such acquisition, the maximum permitted ratio shall be increased by 0.50 to 1.00 above the otherwise relevant level; and

• after we have issued at least $150.0 million of unsecured notes, a Consolidated Senior Secured Leverage Ratio (as defined in the Credit Facility) of not greater than 3.50 to 1.00 (or 4.00 to 1.00 during a Material Acquisition Period).

Our Credit Facility generally prohibits us from making cash distributions (subject to exceptions as set forth in the Credit Facility) except so long as no default exists or would be caused thereby, we may make cash distributions to unitholders up to the amount of our available cash (as defined in our partnership agreement).

The credit agreement contains events of default, including, but not limited to (and subject to grace periods in circumstances set forth in the Credit Agreement), the failure to pay any principal, interest or fees when due, failure to perform or observe any covenant that does not have certain materiality qualifiers contained in the Credit Facility or related loan documentation, any representation, warranty or certification made or deemed made in the agreements or related loan documentation being untrue in any material respect when made, default under certain material debt agreements, commencement of bankruptcy or other insolvency proceedings, certain changes in our ownership or the ownership of our general partner, material judgments or orders, certain judgment defaults, ERISA events or the invalidity of the loan documents. Upon the occurrence and during the continuation of an event of default under the agreements, the lenders may, among other things, terminate their commitments, declare any outstanding loans to be immediately due and payable and/or exercise remedies against us and the collateral as may be available to the lenders under the agreements and related documentation or applicable law.

As of December 31, 2014, we were in compliance with the covenants set forth in our Credit Agreement.

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At December 31, 2014, the capacity on our Credit Facility available to us was approximately $218.6 million, determined as follows:

	(in millions)
Aggregate borrowing capacity under Credit Facility	$	300.0
Less: Term Loan Facility amounts outstanding	81.4
Revolving Credit Facility amounts outstanding	—
Letters of credit outstanding	—
Available Credit Facility capacity	$	218.6

In November 2008, the Predecessor, through USDG, became party to a credit agreement (the “BOK Credit Agreement”) with the Bank of Oklahoma consisting of a revolving credit facility with a borrowing capacity of $150.0 million. The BOK Credit Agreement was guaranteed by all USDG subsidiaries, including us. The outstanding balance under the BOK Credit Agreement was $30.0 million at December 31, 2013, which expanded in 2014 to $97.8 million after borrowing approximately $67.8 million for costs associated with constructing the Hardisty rail terminal. We repaid the entire outstanding balance on October 15, 2014, with proceeds we received from our IPO. We incurred interest expense under the terms of the Credit Agreement at LIBOR plus a margin based on USDG’s leverage ratio, as defined in the BOK Credit Agreement. The average interest rate was 3.90%, 3.92% and 3.96% at December 31, 2014, 2013 and 2012, respectively, in addition to a fee of 0.50% that was charged on the unused portion of the BOK Credit Agreement.

A detail of interest expense from continuing operations is as follows:

	For the Years Ended December 31,
	2014		2013		2012
	(in thousands)
Interest expense on BOK Credit Agreement	$	2,819	$	1,821	$	834
Interest expense on Credit Facility	950		—		—
Amortization of deferred financing costs	1,056		1,420		1,216
Total interest expense	$	4,825	$	3,241	$	2,050

6. DEFERRED REVENUE

Our deferred revenue includes amounts we have received in cash from customers as payment for their minimum monthly commitment fees under take-or-pay contracts, where such payments exceed the charges implied by the customer's actual throughput based on contractual rates set forth in our agreements. In such cases, we grant our customers a credit for periods up to six months, which may be used 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. We refer to these credits as “make-up rights.” We defer revenue associated with make-up rights until the earlier of when the throughput is utilized, the make-up rights expire, or when it is determined that the likelihood that the customer will utilize the make-up right is remote.

Our deferred revenues also include amounts collected from customers in the Fleet services segment, which will be recognized as revenue when earned pursuant to contractual terms. We have prepaid rent associated with these deferred revenues on our railcar leases, which will be recognized as expense when incurred.

The following table provides a detail of deferred revenue as reflected in our consolidated balance sheets :

	As of December 31,
	2014		2013
	(in thousands)
Customer prepayments	$	3,505	$	1,563
Minimum monthly commitment fees	12,035		—
Total deferred revenue, current portion	$	15,540	$	1,563
Customer prepayments	3,656		4,585
Total deferred revenue, net of current portion	$	3,656	$	4,585

7. TRANSACTIONS WITH RELATED PARTIES

Nature of Relationship with Related Parties

USD is a growth-oriented developer, builder, operator and manager of energy-related infrastructure,and is the sole owner of USDG and the ultimate parent of our general partner. USD is owned by Energy Capital Partners, Goldman Sachs and certain members of its management.

USDG is the sole owner of our general partner and prior to the IPO, held a 98.0% limited partner interest in us and retains an aggregate 54.2% limited partner interest following the IPO. USDG also provides us with general and administrative support services necessary for the operation and management of our business.

USD Partners GP LLC, our general partner both before and after the IPO held a 2.0% general partner interest in us. Pursuant to our partnership agreement, our general partner is responsible for our overall governance and operations.

Initial Public Offering Transactions

In connection with our IPO, we entered into agreements regarding the vesting of assets in, and the assumption of liabilities by us and our subsidiaries, and the application of the proceeds from the IPO. 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 USDG 1,093,545 of our common units and all 10,463,545 of our subordinated units, 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 USDG the right to receive $100 million. 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 have entered into various agreements as discussed below with our general partner, USDG and its affiliates on terms that we consider to be no less favorable to us or our subsidiaries than those that could have been negotiated with unaffiliated parties for similar services.

In addition to the above noted transactions and in connection with our IPO, we also sold land in close proximity to our Hardisty rail terminal on October 15, 2014 to USD Terminals Canada ULC II, a wholly-owned subsidiary of USD Group LLC, in exchange for a demand note receivable in the amount of $2.5 million. As a transaction among entities under common control, we did not recognize any gain or loss upon the sale.

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Omnibus Agreement

At the closing of our IPO, we entered into an omnibus agreement with USD and USD Group LLC, certain of our subsidiaries and our general partner that provide for the following matters:

• our payment of an annual amount to USD Group LLC, initially in the amount of approximately $4.9 million, for providing certain general and administrative services by USD Group LLC and its affiliates, which annual amount includes a fixed annual fee of $2.5 million for providing executive management services by officers of our general partner. Other portions of this annual amount are based on the costs actually incurred by USD Group LLC and its affiliates in providing the services;

• our right of first offer to acquire the Hardisty Phase II and Hardisty Phase III projects as well as other additional midstream infrastructure assets and businesses that USD and USD Group LLC may construct or acquire in the future;

• our obligation to reimburse USD Group LLC for any out-of-pocket costs and expenses incurred by USD Group LLC in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement), as well as any other out-of-pocket expenses incurred by USD Group LLC on our behalf;

• an indemnity by USD Group LLC for certain environmental and other liabilities, and our obligation to indemnify USD Group LLC and its subsidiaries for events and conditions associated with the operation of our assets that occur after the closing of the IPO and for environmental liabilities related to our assets to the extent USD Group LLC is not required to indemnify us; and

• so long as USD Group LLC controls our general partner, the omnibus agreement will remain in full force and effect. If USD Group LLC ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of Annual Fee and Reimbursement of Expenses

We pay USD Group LLC, in equal monthly installments, the annual amount USD Group LLC estimates will be payable by us to USD Group LLC during that calendar year for providing services for our benefit. The omnibus agreement provides that this amount may be adjusted annually to reflect, among other things, changes in the scope of the general and administrative services provided to us due to a contribution, acquisition or disposition of assets by us or our subsidiaries or for changes in any law, rule or regulation applicable to us affecting the cost of providing the general and administrative services. We will also reimburse USD Group LLC for any out-of-pocket costs and expenses incurred on our behalf by USD Group LLC in providing general and administrative services to us. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

The total amount charged to us under the Omnibus agreement for the year ended December 31, 2014, was $0.4 million and is recorded in "Selling, general and administrative - related party" in our consolidated statement of operations.

Right of First Offer

Under the omnibus agreement, until the 7th anniversary of the closing of our IPO, prior to engaging in any negotiation regarding the sale, transfer or disposition of (i) the Hardisty Phase II project, (ii) the Hardisty Phase III project or (iii) any other midstream infrastructure assets and business that USD or USDG may develop, construct or acquire, USD or USDG is require to provide written notice to us setting forth the material terms and conditions upon which USD or USDG would sell or transfer such assets or businesses to us. Following the receipt of such notice, we will have 60 days to determine whether the asset is suitable for our business at that particular time, and to propose a transaction with USD or USDG. We and USD or USDG will then have 60 days to negotiate in good faith to reach an agreement on such transaction. If we and USD or USDG, as applicable, are unable to agree on terms during such 60-day period, then USD or USDG, as applicable, may transfer such asset to any third party during a 180-day period

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following the expiration of such 60-day period on terms generally no less favorable to the third party than those included in the written notice.

Our decision to make any offer will require the approval of the conflicts committee of the board of directors of our general partner. The consummation and timing of any acquisition by us of the assets covered by our right of first offer will depend on, among other things, USD or USDG’s decision to sell an asset covered by our right of first offer, our ability to reach an agreement with USD or USDG on price and other terms and our ability to obtain financing on acceptable terms. USD or USDG are 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.

Indemnification

Under the omnibus agreement, USDG has agreed to indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before October 15, 2014, the closing date of our IPO. Indemnification for any unknown environmental liabilities is limited to liabilities due to occurrences on or before October 15, 2014 and are identified prior to October 15, 2017, and are subject to an aggregate deductible of $500,000 before we are entitled to indemnification. Additionally, the omnibus agreement imposes a $10.0 million cap on the amount for which USDG indemnifies us with respect to environmental claims once we meet the deductible, if applicable. USDG also indemnifies us for certain defects in title to the assets contributed to us and failure to obtain certain consents, licenses and permits necessary to conduct our business, including the cost of curing any such condition and certain tax liabilities attributable to the operation of the assets contributed to us prior to the time they were contributed.

USDG also indemnifies us for liabilities, subject to an aggregate deductible of $500,000, relating to:

• the assets contributed to us, other than environmental liabilities, that arise out of the ownership or operation of the assets prior to the closing of the IPO and that are asserted prior to the third anniversary of the closing of the IPO;

• events and conditions associated with any assets retained by USDG; and

• all tax liabilities attributable to the assets contributed to us arising prior to the closing of the IPO or otherwise related to USDG’s contribution of those assets to us in connection with the IPO.

Variable Interest Entities

We have entered into purchase, assignment and assumption agreements to assign payment and performance obligations for certain operating lease agreements with lessors and customer fleet service payments related to these operating leases with LRT Logistics Funding LLC, USD Fleet Funding LLC, USD Fleet Funding Canada Inc., and USD Logistics Funding Canada Inc, which are unconsolidated variable-interest entities (the “VIEs”) with the Predecessor. The managing member of the VIEs is majority-owned by related parties of the Predecessor. We are not the primary beneficiary of the VIEs, as we do not have power to direct the activities that most significantly affect the economic performance of the VIEs, who also maintain substantive kick-out rights. Accordingly, we do not consolidate the results of the VIEs in our consolidated financial statements.

The following table summarizes the total assets and liabilities related to our unconsolidated VIEs as refelected in our consolidated balance sheets, as well as our maximum exposure to losses in which we have a variable interest

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but are not the primary beneficiary. Generally, our maximum exposure to losses is limited to amounts receivable for services we provided, reduced by any unearned deferred revenues.

	At December 31, 2014
	Total assets		Total liabilities		Maximum exposure to loss
	(in millions)
Accounts receivable — related party	$	0.1	$	—	$	—
Deferred revenue, current portion — related party	—		0.6		—
Deferred revenue — related party, net of current portion	—		1.9		—
	$	0.1	$	2.5	$	—

	At December 31, 2013
	Total assets		Total liabilities		Maximum exposure to loss
	(in millions)
Accounts receivable — related party	$	—	$	—	$	—
Deferred revenue, current portion — related party	—		—		—
Deferred revenue — related party, net of current portion	—		1.0		—
	$	—	$	1.0	$	—

Related party sales to the VIEs were $1.5 million, $1.0 million and $0 during the years ended December 31, 2014, 2013 and 2012, respectively. These sales are recorded in "Fleet services - related party" on the accompanying consolidated statements of operations.

Related Party Revenue and Deferred Revenue

We have also entered into agreements with J. Aron & Company (“J. Aron”), a wholly owned subsidiary of The Goldman Sachs Group, Inc. (“GS”), as well as USD Marketing LLC ("USD Marketing"), a wholly owned subsidiary of USDG, to provide terminalling and fleet services, which include reimbursement for certain out-of-pocket expenses, related to the Hardisty rail terminal operations. GS is a principal shareholder of USDG. The terms and conditions of these agreements are similar to the terms and conditions of third-party agreements at the Hardisty rail terminal. J. Aron has entered into assignment arrangements with third parties in respect to these services and may do so again in the future.

Information about related party sales to J. Aron is presented below:

	For the Years Ended December 31,
	2014		2013		2012
	(in millions)
Terminalling services - related party	$	3.5	$	—	$	—
Freight and other reimbursables - related party	0.5		2.6		—
	$	4.0	$	2.6	$	—

Outstanding balances due from J. Aron as of December 31, 2014 and 2013 are $0 and $0.4 million, respectively.

We also received payments totaling $2.0 million from USD Marketing during the year ended December 31, 2014, in connection with their minimum monthly volume commitments at our Hardisty rail terminal, all of which has been recorded in "Deferred revenue, current portion — related party" on our consolidated balance sheets at December 31, 2014. We did not receive similar payments in 2013 or 2012.

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Cost Allocations

Prior to our IPO, USDG allocated overhead costs to us for general and administrative services, including insurance, professional fees, facilities, information services, human resources and other support provided to us. Where costs incurred on our behalf could not be determined by specific identification, the costs were primarily allocated evenly across the number of operating subsidiaries or allocated based on budgeted volumes or projected revenues. We believe these allocations are a reasonable reflection of the utilization of services provided. However, the allocations may not fully reflect the expenses that would have been incurred had we been a stand-alone company during the periods presented. Following our IPO, we are charged these costs as set forth in the Omnibus agreement as discussed above.

The total amount charged to us for overhead cost allocations for the years ended December 31, 2014, 2013 and 2012, which is recorded in "Selling, general and administrative" in the consolidated statements of operations was $3.5 million, $3.0 million and $1.2 million, respectively.

Loan from USDG

On December 13, 2013, USDTC (the Borrower), entered into an unsecured loan facility with USDG (the USDG Loan) for an initial loan amount of $45.2 million CAD with the capacity to increase to $70.0 million CAD. Under the USDG Loan agreement, the Borrower agreed to repay amounts advanced as requested by USDG. The loan facility was restricted for purposes of constructing the Borrower’s terminal at Hardisty, Alberta and expenses relating to its operation. There were no interest charges for advanced amounts outstanding nor was there a termination date included within the USDG Loan agreement. Borrower repaid the amounts outstanding in 2014; as a result, the balance as of December 31, 2014, was $0. At December 31, 2013, the balance was $51.0 million as presented on our consolidated balance sheets.

8. PARTNERS' CAPITAL

The common units and subordinated units represent limited partner interests in us. The holders of common units and subordinated units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement.

The Class A units are limited partner interests in our partnership that entitle the holders to nonforfeitable distributions that are equivalent to the distributions paid in respect of our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and as a result are considered participating securities. The Class A units do not have voting rights and will vest in four equal annual installments over the first four years following the consummation of the IPO only if we grow our annualized distributions each year. If we do not achieve positive distribution growth in any of these years, the Class A units that would otherwise vest for that year will be forfeited. The Class A units contain a conversion feature, which, upon the vesting of the Class A units, provides for the conversion of the Class A units into common units based on a conversion factor that is tied to the level of our distribution growth for the applicable year. The conversion factor will not be more than 1.25 for the first vesting tranche, 1.5 for the second vesting tranche, 1.75 for the third vesting tranche and 2.0 for the last vesting tranche.

Our partnership agreement provides that, while any subordinated units remain outstanding, the common units and Class A units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to our minimum quarterly distribution of $0.2875 per unit, plus (with respect to the common units) any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

Subordinated units will convert into common units on a one-for-one basis in separate sequential tranches. Each tranche will be comprised of 20.0% of the subordinated units outstanding immediately following the IPO. A separate tranche will convert on each business day occurring on or after December 31, 2015 (but no more than once in any twelve-month period), provided on that date (i) distributions of available cash from operating surplus on each of the outstanding common units, Class A units, subordinated units and general partner units equaled or exceeded $1.15 per unit (the annualized minimum quarterly distribution) for the four quarter period immediately preceding that date; (ii) the adjusted operating surplus generated during the four quarter period immediately preceding that date equaled or exceeded the sum of $1.15 per unit (the annualized minimum quarterly distribution) on all of the common units, Class A units, subordinated units and general partner units outstanding during that period on a fully diluted basis; and (iii)

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there are no arrearages in the payment of the minimum quarterly distribution on the common units. For each successive tranche, the four quarter period specified in clauses (i) and (ii) above must commence after the four quarter period applicable to any prior tranche of subordinated units.

The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) on all of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. The amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

9. COLLABORATIVE ARRANGEMENTS

We entered into a facilities connection agreement in 2014 with Gibson under which Gibson developed, constructed and operates a pipeline and related facilities connecting to our Hardisty rail terminal. Gibson’s storage terminal is the exclusive means by which our Hardisty rail terminal receives crude oil. Subject to certain limited exceptions regarding manifest train facilities, this pipeline to our Hardisty rail terminal is the exclusive means by which crude oil from the Gibson storage terminal may be transported by rail. We remit pipeline fees to Gibson for the transportation of crude oil to the Hardisty rail terminal based on a predetermined formula. For the year ended December 31, 2014, we recorded $3.6 million as "Pipeline fees" on our consolidated statements of operations.

10. COMMITMENTS AND CONTINGENCIES

Fleet Lease Income

We serve as lessor on non-cancelable operating leases with customers who are required to pay minimum balances under an agreement for railcars that are currently being leased by us under non-cancelable operating leases. These agreements run through 2021. Under these agreements, we recognized lease income of $8.8 million, $13.6 million and $16.0 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, which are recorded in "Fleet leases" on our consolidated statements of operations. We did not have any contingent rentals with respect to these periods.

The following table presents future minimum lease rentals due to us under non-cancelable railcar operating leases (in thousands):

	As of December 31,
2015	$	9,006
2016	5,139
2017	4,961
2018	4,070
2019	4,070
Thereafter	7,462
Total	$	34,708

Rail Service Agreements

We have rail service agreements at our terminal facilities with labor service providers that expire at various dates from 2015 through 2019.

After the initial term of the agreements, the rail service contracts will continue to be in effect for consecutive one-year terms unless either party provides the other party written notice prior to end of the term. Under these agreements, we incurred approximately $7.0 million, $1.9 million and $1.8 million in service fees for the years ended December 31,

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2014, 2013 and 2012, respectively, which are recorded in "Subcontracted rail services" on our consolidated statements of operations.

The future minimum payments for these rail services agreements are as follows (in thousands):

	As of December 31,
2015	$	8,460
2016	7,549
2017	7,700
2018	7,854
2019	2,635
Total	$	34,198

Operating Leases

We have non-cancellable operating leases for buildings, office facilities, railroad tracks, land surfaces, and railcars that expire on various dates from 2015 through 2021. We incurred $0.3 million, $0.3 million and $0.2 million in lease expenses related to buildings, offices, tracks, and land for the years ended December 31, 2014, 2013 and 2012, respectively, which are recorded in "Selling, general & administrative" in our consolidated statements of operations.

We incurred fleet service expenses of $8.8 million, $13.6 million and $16.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, which are recorded in fleet leases on our consolidated statements of operations.

The approximate amount of our future minimum lease payments under noncancelable operating leases are as follows (in thousands):

	As of December 31
2015	$	9,273
2016	5,226
2017	5,051
2018	4,070
2019	4,070
Thereafter	7,462
	$	35,152

At December 31, 2014 we did not have any material commitments for construction activities due to the completion and commissioning in June 2014 of our Hardisty rail terminal. At December 31, 2013, we had major construction contracts for approximately $67.9 million, which included approximately $45.0 million in contracts that were completed and $22.9 million to be incurred in future periods.

Of the $3.7 million classified as other current liabilities on the consolidated balance sheet as of December 31, 2013, $3.6 million consisted of funds necessary to pay construction retention balances related to the build-out of the Hardisty rail terminal.

Contingent Liabilities

From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. We do not believe that we are currently a party to any litigation that will have a material impact on our financial condition or results of operations.

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11. SEGMENT REPORTING

We manage our business in two reportable segments: Terminalling services segment and Fleet services segment. The Terminalling services segment operates by terminalling and transloading crude oil and biofuels under multi-year, fee-based contracts. The Fleet services segment manages a fleet of rail cars to ensure customer’s products are handled safely and efficiently.

Our segments offer different services and are managed accordingly. 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").

The following tables summarize our reportable segment data for continuing operations:

	For the Year Ended December 31, 2014
	Terminalling services			Fleet services			Corporate (1)			Total
	(in thousands)
Revenues:
Terminalling services	$	18,266		$	—		$	—		$	18,266
Terminalling services - related party	3,499			—			—			3,499
Railroad incentives	719			—			—			719
Fleet leases	—			8,788			—			8,788
Fleet services	—			720			—			720
Fleet services – related party	—			1,501			—			1,501
Freight and other reimbursables	—			2,141			—			2,141
Freight and other reimbursables - related party	—			464			—			464
Total revenue	22,484			13,614			—			36,098
Operating costs:
Subcontracted rail services	6,994			—			—			6,994
Pipeline fees	3,625			—			—			3,625
Fleet leases	—			8,788			—			8,788
Freight and other reimbursables	—			2,605			—			2,605
Selling, general and administrative	6,290			2,650			1,868			10,808
Depreciation	2,631			—			—			2,631
Total operating costs	19,540			14,043			1,868			35,451
Operating income (loss)	2,944			(429		)	(1,868		)	647
Interest expense	3,600			—			1,225			4,825
Gain associated with derivative instruments	(1,536		)	—			—			(1,536		)
Foreign currency transaction loss (gain)	4,406			(17		)	461			4,850
Provision (benefit) for income taxes	47			140			(1		)	186
Loss from continuing operations	$	(3,573	)	$	(552	)	$	(3,553	)	$	(7,678	)
Total assets	$	105,093		$	7,692		$	40,867		$	153,652
Capital expenditures	$	33,736		$	—		$	—		$	33,736

⁽¹⁾  Corporate activities represents corporate and financing activities that are not allocated to the established reporting segments.

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	For the Year Ended December 31, 2013
	Terminalling services			Fleet services		Corporate (1)			Total
	(in thousands)
Revenues
Terminalling services	$	7,130		$	—	$	—		$	7,130
Fleet leases	—			13,572		—			13,572
Fleet services	—			235		—			235
Fleet services – related party	—			962		—			962
Freight and other reimbursables	—			1,778		—			1,778
Freight and other reimbursables - related party	—			2,624		—			2,624
Total revenue	7,130			19,171		—			26,301
Operating costs:
Subcontracted rail services	1,898			—		—			1,898
Fleet leases	—			13,572		—			13,572
Freight and other reimbursables	—			4,402		—			4,402
Selling, general and administrative	3,704			380		374			4,458
Depreciation	502			—		—			502
Total operating costs	6,104			18,354		374			24,832
Operating income (loss)	1,026			817		(374		)	1,469
Interest expense	3,241			—		—			3,241
Other expense, net	39			—		—			39
Provision for income taxes	21			9		—			30
Income (loss) from continuing operations	$	(2,275	)	$	808	$	(374	)	$	(1,841	)
Total assets	$	68,995		$	8,197	$	—		$	77,192
Capital expenditures	$	56,114		$	—	$	—		$	56,114

⁽¹⁾  Corporate activities represents corporate and financing activities that are not allocated to the established reporting segments.

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	For The Year Ended December 31, 2012
	Terminalling services		Fleet services			Corporate (1)			Total
	(in thousands)
Revenues
Terminalling services	$	8,703	$	—		$	—		$	8,703
Fleet leases	—		15,964			—			15,964
Fleet services	—		5			—			5
Freight and other reimbursables	—		203			—			203
Total revenue	8,703		16,172			—			24,875
Operating costs
Subcontracted rail services	1,847		—			—			1,847
Fleet leases	—		15,964			—			15,964
Freight and other reimbursables	—		203			—			203
Selling, general and administrative	3,000		114			126			3,240
Depreciation	490		—			—			490
Total operating costs	5,337		16,281			126			21,744
Operating income (loss)	3,366		(109		)	(126		)	3,131
Interest expense	2,050		—			—			2,050
Provision for income taxes	26		—			—			26
Income (loss) from continuing operations	$	1,290	$	(109	)	$	(126	)	$	1,055
Total assets	$	14,128	$	3,505		$	—		$	17,633
Capital expenditures	$	773	$	—		$	—		$	773

⁽¹⁾  Corporate activities represents corporate and financing activities that are not allocated to the established reporting segments.

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Segment Adjusted EBITDA

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⁾  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.

The following tables summarize the geographic data for our continuing operations:

	For The Year Ended December 31, 2014
	U.S.		Canada		Total
	(in thousands)
Revenues
Third party	$	17,049	$	13,585	$	30,634
Related party	1,933		3,531		5,464
Total assets	$	56,339	$	97,313	$	153,652

	For The Year Ended December 31, 2013
	U.S.		Canada		Total
	(in thousands)
Revenues
Third party	$	22,715	$	—	$	22,715
Related party	3,586		—		3,586
Total assets	$	17,825	$	59,367	$	77,192

	For The Year Ended December 31, 2012
	U.S.		Canada		Total
	(in thousands)
Revenues
Third party	$	24,875	$	—	$	24,875
Total assets	$	16,890	$	743	$	17,633

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12. MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

The following table provides the percentage of total revenues attributable to a single customer from which 10% or more of total revenues are derived:

	Percent of Total Revenues for Years Ended December 31,
	2014		2013		2012
Customer A	28	%	52	%	43	%
Customer B	18	%	23	%	25	%
Customer C	10	%	10	%	—
Customer D	10	%	3	%	20	%
All Others	34	%	12	%	12	%
	100	%	100	%	100	%

A substantial portion of our revenues are from a limited number of customers. Our revenues are derived mainly from railcar loading and unloading services for bulk liquid products, switching, other terminalling services, and railcar fleet services. The industry concentration of these customers may impact our overall exposure to credit risk, either positively or negatively, since our customers may be similarly affected by changes in commodity prices, regulation, and other economic factors. We seek high-quality customers with investment grade credit ratings and perform ongoing credit evaluations of our customers.

13. INCOME TAXES

As of December 31, 2014 and 2013 we have no uncertain tax positions that qualify for either recognition or disclosure in our consolidated financial statements.

The income tax returns filed by USD for the periods from January 1, 2009 through December 31, 2013 are subject to examination by the taxing authorities. The results of such examinations may impact us as the results of any findings could pass down us. Income tax returns for our Canadian operations filed for the period ended December 31, 2013 are subject to examination by the taxing authorities. At December 31, 2014, neither we nor our Canadian operations are currently under examination.

We are treated as a partnership for federal and most state income tax purposes, with each partner being separately taxed on its share of taxable income, except for USD Rail LP which, on October 7, 2014, elected to be classified as an entity taxable as a corporation. Our provision for income taxes for the years presented includes franchise taxes and taxes on USD Rail LP and our Canadian operations. For the years ended December 31, 2014, 2013, and 2012, our provision for U.S. income taxes consisted of current expense for state franchise and foreign minimum taxes of $186 thousand, $30 thousand and $26 thousand, respectively. We have not recognized a benefit for losses associated with our U.S. and Canadian operations, since we currently consider it to be more likely than not that the benefit from the loss carryover will not be realized. Our U.S. loss carryover is approximately $0.7 million at December 31, 2014, which will expire in 2034. The Canadian loss carryover was approximately $8.5 million and $0.2 million, respectively, as of December 31, 2014 and 2013, which will start expiring in 2033. We did not have any unrecognized tax benefits or any tax reserves for uncertain tax positions at December 31, 2014 or 2013.

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The components of income (loss) before taxes with reconciliation between tax at the federal statutory rate and actual income tax expense for continuing operations follow:

	Years Ended December 31,
	2014			2013			2012
	(in thousands)
Domestic	$	(2,374	)	$	(1,527	)	$	1,081
Foreign	(5,118		)	(284		)	—
Total income (loss) before taxes	$	(7,492	)	$	(1,811	)	$	1,081
Tax expense (benefit) at the statutory rate	$	(2,547	)	$	(634	)	$	378
Loss (income) attributable to partnership not subject to tax	933			536			(378		)
Foreign tax rate differential	313			28			—
Other	—			10			—
State income tax	156			30			26
Change in valuation allowance	1,331			60			—
Provision for income taxes	$	186		$	30		$	26

Our deferred income taxes reflect the tax effect of differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred income tax assets for continuing operations follow:

	As of December 31,
	2014			2013
	(in thousands)
Deferred income tax assets
Property and equipment	$	(946	)	$	25
Capital and operating loss carryovers	1,496			35
Prepaid expense	(1,098		)	—
Deferred revenues	1,939			—
Valuation allowance	(1,391		)	(60		)
Net deferred income tax assets	$	—		$	—

14. DERIVATIVE FINANCIAL INSTRUMENTS

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in foreign currency exchange rates, particularly with respect to the U.S. dollar and the Canadian dollar. At December 31, 2014 and 2013, we did not employ any derivative financial instruments to manage our exposure to fluctuations in interest rates, although we may use derivative financial instruments, including swaps, options and other financial instruments with similar characteristics to manage this exposure in the future.

A majority of the cash flows we produce are derived from our Hardisty rail terminal operations in the province of Alberta, Canada. As a result, fluctuations in the exchange rates between the Canadian dollar and the U.S. dollar could have a significant effect on our results of operations, cash flows and financial position. In order to manage our exposure to fluctuations in foreign currency exchange rates and the related risks to our unitholders, we use derivative financial instruments to offset these risks. We have a program that primarily utilizes foreign currency collar derivative contracts, representing written call options and purchased put options, to reduce the risks associated with the effects of foreign currency exposures related to our Canadian subsidiaries which have cash flows denominated in Canadian dollars. Under this program, our strategy is to employ derivative contracts to mitigate the foreign currency transaction gains or losses to the extent practical. Economically, the collars limit our exposure such that the exchange rate effectively lies between the floor and the ceiling rates set forth in the derivative contacts. All of our derivative financial instruments

are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into for speculative purposes.

Derivative Positions

We did not enter into any derivative contracts during the years ended December 31, 2013. In May 2014 we entered into collar arrangements with a notional value of $37.2 million CAD on the date executed, which uses put and call options to limit the amount of loss or gain that we will receive upon converting the notional value to U.S. dollars. These put and call options pertain to the three month periods ending December 31, 2014, March 31, 2015, June 30, 2015, September 30, 2015, and December 31, 2015. The collar was executed to secure $37.2 million CAD at an exchange rate range between 0.91 and 0.93 U.S. dollars to 1.00 Canadian dollar. We have not designated these derivative financial instruments as hedges of our foreign currency rate exposures, but instead we mark these contracts to fair value quarterly with the change in fair value recorded to "Gain associated with derivative instruments" in our consolidated statements of operations. For the year ended December 31, 2014, we recognized gains of $1.5 million in our consolidated statements of operations related to changes in the fair value of our derivative contracts. The gains or losses associated with changes in the fair value of our foreign currency derivative contracts do not affect our cash flows until the underlying contract is settled by making or receiving a payment to or from the counterparty.

We have presented the fair value of our derivative financial instruments in "Prepaid expenses and other current assets" in our consolidated balance sheet at December 31, 2014. We determine the fair value of our derivative financial instruments using third party pricing information that is derived from observable market inputs, which we classify as level 2 with respect to the fair value hierarchy. The following table presents summarized information about the fair values of our outstanding foreign currency contracts at December 31, 2014:

					Fair Value
					(in thousands)
	Notional (CAD)		Strike Price (1)	Market Price (1)	Asset		Liability
Portion of option contracts maturing in 2015
Puts (purchased)	$	29,722,200	0.9100	0.8606	$	1,660	$	—
Calls (written)	$	29,722,200	0.9300	0.8606	$	—	$	—

(1)    Strike and market price is denoted in CAD/USD.

15. UNIT BASED COMPENSATION

Class A units

In connection with our IPO and as provided for in our partnership agreement, we granted 250,000 non-voting Class A units to certain executive officers and other key employees of our general partner who provide services to us, of which 30,000 were forfeited in December 2014. None of the Class A units granted in 2014 are vested as of December 31, 2014.

The Class A units vest over a four year period depending upon the attainment of established distribution target thresholds for each year in the four year vesting period. If distributions exceed the threshold by more than the target amount, the Class A units in that tranche vest and become convertible into more than one common unit (1.25 to 2.0 times common units per Class A unit, depending on the tranche). Each of the Class A units have distribution equivalent rights (“DERs”) until they are forfeited, expire or are terminated. However, distributions over the vesting period are not paid in arrearage if the Class A units become convertible into more than one common unit.

We measure the compensation cost associated with the Class A units based on the fair value at the effective date of the grant, representing the October 8, 2014 date our common units began trading on the NYSE. We determined the fair value of our Class A units the grant date to be $25.71 per Class A unit based on the market price of the underlying common units on the date of our IPO, adjusted for vesting probabilities associated with the

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performance-based vesting requirements and the present value of the expected distributions. We assumed distribution rates ranging from $0.24375 per quarter to $0.4905 per quarter during the vesting period which we discounted assuming a 13% annual cost of equity.

The ultimate percentage of units vesting in each tranche depends on a performance condition: specifically, the distributions paid in the last year of the vesting period for each tranche. If distributions meet or fall below a threshold, the Class A units in that tranche are forfeited. If distributions exceed a threshold by less than a target amount, the Class A units in that tranche vest and become convertible into one common unit. If distributions exceed the threshold by more than the target amount, the Class A units in that tranche vest and become convertible into more than one common unit (1.25 to 2.0 times common units per Class A unit, depending on the tranche). We did not assume any forfeitures in our determination of fair value.

We estimated the expense for each tranche as the number of unit equity awards, multiplied by the per unit grant date fair value of those awards less estimated forfeitures in the probable vesting scenario for each tranche (equaling the applicable conversion multiple times the value of the stock excluding the expected distributions paid over the vesting period (the common unit price at IPO less the present value of the expected distributions) plus the present value of the expected distributions for any tranches that vest). The estimated fair value of our Class A units is amortized over the four-year vesting period using the accelerated attribution model. The Class A units awards will convert into our common units upon the vesting. We recognized approximately $0.6 million as compensation expense for the year ended December 31, 2014, related to the Class A units granted, which costs are included in “Selling, general and administrative” in our consolidated statements of operations.

16. SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental cash flow information:

	For the Years Ended December 31,
	2014		2013		2012
	(in thousands)
Cash paid for income taxes	$	101	$	26	$	38
Cash paid for interest	$	3,588	$	1,829	$	2,563
NON-CASH INVESTING ACTIVITIES
Sale of land for note receivable - related party	$	2,472	$	—	$	—

17. DISCONTINUED OPERATIONS

On December 12, 2012, USDG sold all of its membership interests in five of its subsidiaries previously included in our Terminalling services segment to the Acquirer. The sales price of the subsidiaries was $502.6 million, net of working capital adjustments. USDG used a portion of these proceeds to pay down its bank debt to $30.0 million at the time of the sale and for distributions to its members during the periods presented. For the years ended December 31, 2013 and 2012, the we have $7.3 million and $394.3 million, respectively, recorded as gain on sale of discontinued operations.

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Assets and liabilities of our Discontinued Operations are as follows:

	As of December 31, 2013
	(in thousands)
Assets:
Cash	$	—
Receivables	603
Cash proceeds placed in escrow related to the sale	29,473
Total assets	$	30,076
Liabilities:
Payables	$	—
Bonus accrued for payment to employees	5,835
Total liabilities	$	5,835

The following table shows results from our Discontinued Operations:

	For the year ended December 31,
	2013		2012
	(in thousands)
Discontinued operations:
Revenues	$	951	$	107,714
Income before provision for income taxes	951		65,245
Provision for income taxes	3		41
Net income (loss)	$	948	$	65,204

The following table provides a reconciliation of our sales price for the Discontinued Operations to our gain on sale of discontinued operations:

	For the Year Ended December 31, 2012
	(in thousands)
Sales price	$	502,554
Subsidiaries sold at cost	(72,564		)
Transaction costs and other	(35,672		)
Gain on sale of discontinued operations	$	394,318

The following table provides a reconciliation of the our sales price for the Discontinued Operations to the net cash provided by investing activities for the Discontinued Operations:

	For the Year Ended December 31, 2012
	(in thousands)
Sales price	$	502,554
Gross cash proceeds placed in escrow	(40,000		)
Additions of property and equipment	(26,644		)
Working capital adjustment	852
Net cash provided by investing activities	$	436,762

During 2013, $10.0 million of escrow payments were received.

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Continuing Cash Flows from Discontinued Operations

At the time of the Sale, SJRT had an existing contract (the “Contract”) with one of its customers (the “Customer”) in which the Customer would pay SJRT an Incremental Throughput Fee, as defined, for certain volumes coming through SJRT (“Incremental Throughput Fee”). The Incremental Throughput Fee allowed SJRT to participate with the Customer in the value created due to increased market spreads on the price of crude oil. The Incremental Throughput Fee was calculated at a certain percentage of the net differential between the market price of the crude oil volumes and an agreed upon minimum price. Upon the sale of SJRT, the Acquirer agreed to remit the Incremental Throughput Fee to us until the expiration of the Contract. We received these cash flows through September of 2013. These proceeds are recorded as income from discontinued operations prior to the Sale and in gain on sale of discontinued operations after the Sale as the remittance of the Incremental Throughput Fee after the Sale is deemed a resolution of a purchase price adjustment with the Acquirer. During the years ended December 31, 2013 and 2012, $7.3 million and $0.9 million, respectively, are recorded in gain on sale of discontinued operations.

In conjunction with the Sale, we ceased the operations of another subsidiary, USDS, which primarily provided loading and unloading services to the Acquirer, pursuant to a service agreement. Effective at the closing date of the Sale, USDS assigned or terminated any obligations it had in relation to its operations, but continues to receive indirect cash flows. We have not participated in any revenue producing activities with respect to USDS and the cash flows terminated upon the expiration of the assigned service agreement on February 15, 2015. The earnings from the assigned service agreement are recorded as income from discontinued operations are $0, $1.0 million and $46 thousand for the years ended December 31, 2014, 2013 and 2012, respectively.

18. SUBSEQUENT EVENTS

Distribution to Partners

On January 29, 2015, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a cash distribution payable of $0.24375 per unit for the quarter ended December 31, 2014. We paid the distribution on February 13, 2015 to unitholders of record on February 9, 2015. The cash distribution represents the prorated amount of our targeted minimum quarterly distribution of $0.28750 per unit, or $1.15 per unit on an annualized basis, for the period from October 15, 2014, the completion of our IPO, through December 31, 2014. We paid $2.2 million to our public Common unitholders, $53,625 to the Class A unitholders, an aggregate of $2.8 million to USD Group LLC as the holders of Common units and our Subordinated units and $104 thousand to USD Partners GP LLC for their general partner interest.

Long-term Incentive Plan

On February 16, 2015, the board of directors of our general partner, acting in its capacity as the general partner of USDP approved the grant of 415,608 phantom unit awards ("Phantom Units") in the aggregate to directors and employees of our general partner and its affiliates under the USD Partners LP 2014 Long-Term Incentive Plan (the "LTIP"). The Phantom Units are subject to all of the terms and conditions of the LTIP and the Phantom Unit award agreements (the "Award Agreements"). Phantom Unit awards generally represent rights to receive our common units, or with respect to certain of the awards, cash equal to the fair value of our common units, upon vesting.

The Award Agreements set forth the terms of grants of Phantom Units to participants under the LTIP. Each Phantom Unit granted under the Award Agreement includes an accompanying distribution equivalent right, which entitles the grantee to receive payments equal in amount to any distributions we make with respect to our common units underlying the Phantom Units. The Award Agreements granted to employees of our general partner contemplate that individual grants of Phantom Units will vest in four equal annual installments based on the grantee’s continued employment through the vesting dates specified in the Award Agreements, subject to acceleration upon the grantee’s death or disability, or involuntary termination in connection with a change in control of the Partnership or our general partner. Awards to independent directors of the board of our general partner typically vest over a one year period following the grant date. Award amounts for these grants were generally determined by reference to a specified dollar amount determined based on an allocation formula which included a percentage multiplier of the grantee's base salary,

among other factors, converted to a number of units based on the initial public offering price of our common units in October 2014 of $17.00 per unit.

19. QUARTERLY FINANCIAL DATA (Unaudited)

	First			Second			Third			Fourth			Total
	(in thousands, except per unit amounts)
2014 Quarters
Operating revenue	$	5,485		$	5,436		$	12,986		$	12,191		$	36,098
Operating expense	$	5,477		$	7,216		$	10,963		$	11,795		$	35,451
Operating income (loss)	$	8		$	(1,780	)	$	2,023		$	396		$	647
Loss from continuing operations	$	(1,071	)	$	(4,199	)	$	(1,179	)	$	(1,229	)	$	(7,678	)
Income (loss) from discontinued operations	$	225		$	(194	)	$	(183	)	$	152		$	—
Net loss	$	(846	)	$	(4,393	)	$	(1,362	)	$	(1,077	)	$	(7,678	)
Net loss attributable to limited partner ownership interests in USD Partners LP	$	(829	)	$	(4,305	)	$	(1,335	)	$	(1,055	)	$	(7,524	)
Net loss per limited partner unit	$	(0.02	)	$	(0.37	)	$	(0.12	)	$	(0.06	)	$	(0.55	)
2013 Quarters
Operating revenue	$	8,061		$	5,319		$	5,133		$	7,788		$	26,301
Operating expense	$	7,552		$	5,001		$	5,018		$	7,261		$	24,832
Operating income	$	509		$	318		$	115		$	527		$	1,469
Loss from continuing operations	$	(264	)	$	(571	)	$	(770	)	$	(236	)	$	(1,841	)
Income from discontinued operations	$	4,049		$	2,854		$	1,098		$	242		$	8,243
Net income	$	3,785		$	2,283		$	328		$	6		$	6,402
Net income attributable to limited partner ownership interests in USD Partners LP	$	3,709		$	2,237		$	321		$	6		$	6,274
Net income (loss) per limited partner unit	$	0.32		$	0.19		$	0.03		$	(0.02	)	$	0.54

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not Applicable.

Item 9A. Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Annual Report at the reasonable assurance level.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management’s Annual Report on Internal Control Over Financial Reporting

This Annual Report does not include a report of management’s assessment regarding internal control over financial reporting due to a transition period established by rules of the SEC for new public companies.

ATTESTATION REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

This Annual Report does not include an attestation report of our independent registered public accounting firm on our internal control over financial reporting due to a transition period established by rules of the SEC for new public companies, and because Section 103 of the Jumpstart Our Business Startups Act of 2012 provides that an emerging growth company ("EGC") is not required to provide an auditor’s report on internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act for as long as we qualify as an EGC.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

EXECUTIVE OFFICERS AND DIRECTORS

We are managed by the directors and executive officers of our general partner, USD Partners GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. USD indirectly owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner’s board of directors has eight directors, two of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner's board of directors has affirmatively determined that Ms. O’Hagan and Mr. Wood are independent as described in the rules of the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Set forth below is certain information concerning the directors and executive officers of our general partner, USD Partners GP LLC. Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the executive officers and directors of USD Partners GP LLC:

Name	Age	Position
Dan Borgen	53	Chairman of the Board, Chief Executive Officer and President
Paul Tucker	74	Senior Vice President, Chief Operating Officer
Adam Altsuler	41	Vice President, Chief Financial Officer
Chris Robbins	42	Vice President, Chief Accounting Officer
Guillermo Sierra	30	Vice President, Chief Strategy Officer and Head of M&A
Keith Benson	42	General Counsel
Mike Curry	61	Director
Sara Graziano	32	Director
Douglas Kimmelman	54	Director
Thomas Lane	58	Director
Jane O’Hagan	51	Director
Brad Sanders	57	Director
Jeff Wood	44	Director

Dan Borgen.    Mr. Borgen has been Chief Executive Officer and President of our general partner since June 2014 and became Chairman of the Board of our general partner prior to the close of our IPO. Mr. Borgen is a co-founder of USD and its predecessor companies and has served as chairman, CEO and President of USD since its inception. Additionally, Mr. Borgen served as President of U.S. Right-of-Way Corporation, a private company, since 1993. Prior to USD, Mr. Borgen worked for 11 years in investment banking in mergers and acquisitions, portfolio management and strategic planning. He began his career with a private investment firm focused on the oil and gas industry. Mr. Borgen has served on the board of directors of several corporations and currently serves on the board of Vertex Energy Inc., an environmental services company that recycles industrial waste streams and off-specification commercial chemical products. Active in several community organizations, he is chair of the USD Foundation and a trustee of Boys and Girls

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Club of America. Mr. Borgen received a degree in Petroleum Management and Finance from the University of Oklahoma. He was recognized by Goldman Sachs as one of 100 Most Intriguing Entrepreneurs in 2013 and was a finalist for Ernst and Young’s 2014 Gulf Coast Entrepreneur of the Year. Mr. Borgen’s experience in founding and leading USD and its predecessors provides the board with broad business and leadership expertise in the financial and energy industries.

Paul Tucker.    Mr. Tucker has been Senior Vice President and Chief Operating Officer of our general partner since June 2014. Mr. Tucker also has been the Chief Operating Officer for USD since its inception and, as such, is responsible for the management of all company operating facilities. Mr. Tucker’s career in the rail transportation industry spans over 41 years and includes key senior leadership roles on the Union Pacific, Missouri Pacific and Port Terminal Railroad Association (PTRA). Mr. Tucker’s career also includes service on the board of directors of the Texas City Terminal (TCT), the Galveston, Houston and Henderson (GH&H), the Wichita Terminal Association (WTA) and the Houston Belt and Terminal (HBT) Railroads, on which he also served on the Executive Committee. Mr. Tucker received a BA in Psychology from Henderson State University and received post-graduate executive leadership development at the University of Pittsburgh and Eckerd College, St. Petersburg, Florida.

Adam Altsuler.    Mr. Altsuler has been Vice President and Chief Financial Officer of our general partner since June 2014. Mr. Altsuler joined USD in April 2014 as Vice President, Finance with a primary focus on corporate finance, capital markets and investor relations activities. From 2009 to 2014, Mr. Altsuler served in various leadership roles at Eagle Rock Energy Partners, a master limited partnership headquartered in Houston, Texas most recently serving as Vice President and Treasurer. Prior to joining Eagle Rock, Mr. Altsuler was an Investment Analyst at Kenmont Investments, an energy-focused hedge fund located in Houston, where he managed the fund’s master limited partnership investment portfolio from 2007 to 2009. Prior to Kenmont, Mr. Altsuler worked the majority of his career in investment banking with Donaldson, Lufkin and Jenrette/Credit Suisse First Boston and a boutique investment bank in Dallas and San Francisco. Mr. Altsuler graduated from the University of Texas at Austin with a BBA in Finance and received an MBA from Rice University, graduating Beta Gamma Sigma.

Chris Robbins.    Mr. Robbins has been Vice President and Chief Accounting Officer of our general partner since June 2014. Mr. Robbins joined USD in August 2007 as Chief Accounting Officer and became Vice President, Chief Financial and Accounting Officer in June 2014. Mr. Robbins is primarily focused on corporate finance, accounting and reporting, planning and tax. Prior to joining USD, Mr. Robbins served as Director of Finance for SGS Group’s North American Oil, Gas & Chemicals Division from 1997 to 2007. Mr. Robbins is a Certified Public Accountant, Chartered Global Management Accountant, and holds a B.S. in Accounting from Grove City College in Pennsylvania.

Guillermo Sierra.    Mr. Sierra has been Vice President, Chief Strategy Officer and Head of M&A of our general partner since June 2014. Mr. Sierra joined USD in September 2013 as Vice President, Head of Corporate Strategy and M&A and became Vice President, Chief Strategy Officer and Head of M&A in June 2014. Mr. Sierra is primarily focused on USD’s corporate and capital strategy, acquisitions and other capital markets activities. From September 2009 to September 2013, Mr. Sierra was part of the midstream/master limited partnership M&A team for Evercore Partners in Houston where he executed over 40 announced advisory and IPO transactions representing a combined total transaction value of over $90.0 billion. Prior to Evercore, Mr. Sierra was part of the Natural Resources Group of Barclays Capital, previously Lehman Brothers, where he executed numerous advisory engagements and capital markets transactions with a focus on midstream businesses and master limited partnerships. Mr. Sierra graduated Cum Laude from the Wharton School of the University of Pennsylvania, where he received a B.S. in Economics with concentrations in Finance and Operations & Information Management.

Keith Benson.    Mr. Benson became General Counsel of our general partner and Co-General Counsel of USD in March 2015. From January 2008 through February 2015, Mr. Benson was a partner with the international law firm of Latham & Watkins LLP in their Houston and San Francisco offices. Mr. Benson’s practice focused on public company representation, corporate governance, capital markets and mergers & acquisitions, with a focus on midstream and upstream energy companies, master limited partnerships and real estate investment trusts. From July 2000 through December 2007, Mr. Benson was an associate with Latham & Watkins LLP and from October 1998 through June 2000 Mr. Benson was an associate with the law firm of Cahill, Gordon & Reindel LLP. Mr. Benson received a J.D. with high honors from Rutgers School of Law and a B.A. in Political Science from The College of New Jersey.

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Mike Curry.    Mr. Curry has been a member of the board of directors of our general partner since June 2014. Mr. Curry is co-founder of USD and its predecessor companies, and currently serves as Executive Vice President and Head of Finance and Risk for USD. From 2006 to June 2014, Mr. Curry served as Chief Financial Officer of USD. Throughout the years he has been extensively involved with and directed numerous aspects of USD, including strategic planning, project development, construction and heading finance. Prior to USD, Mr. Curry served as Treasurer and Chief Accounting Officer for integrated oil and gas producer An-Son Corp., located in Oklahoma City, from 1982 to 1985 and was employed by Arthur Andersen & Co. from 1978 to 1981. Mr. Curry is a Certified Public Accountant and holds a Master’s Degree in Accountancy from the University of Illinois. Mr. Curry’s experience and involvement with USD from its founding to its present day operations, along with his accounting background, bring the board financial, strategic and operational expertise and leadership.

Sara Graziano.    Ms. Graziano has been a member of the board of directors of our general partner since October 2014. Ms. Graziano is also a Vice President at Energy Capital Partners. She is involved in all areas of the firm’s investment activities, including the midstream, oilfield services and power generation sectors. Ms. Graziano serves on the board of ProPetro Holding Corp. Prior to joining Energy Capital Partners in 2011, Ms. Graziano worked as a Summer Associate for Energy Capital Partners during business school. Prior to that, Ms. Graziano led the Strategies & Analysis group at FirstLight Power Enterprises, Inc., an Energy Capital Partners Fund I portfolio company, from 2007 to 2009, focusing on commodity trading and hedging strategies and business development activities. Before joining FirstLight, Ms. Graziano spent four years at Charles River Associates, consulting for clients in the power and natural gas industries, with a particular focus on the development of proprietary tools for fundamental and statistical modeling of commodity prices and volatility. Ms. Graziano received a B.A. in Economics from Wellesley College and an M.B.A. from Harvard Business School where she was a Baker Scholar. Ms. Graziano’s experience in the energy industry, including her involvement in Energy Capital Partners’ energy investment activities bring unique analytical, strategic and leadership insight to the board.

Douglas Kimmelman.     Mr. Kimmelman has been a member of the board of directors of our general partner since October 2014. Mr. Kimmelman founded Energy Capital Partners in April 2005 and serves as its Senior Partner. Mr. Kimmelman currently serves on the boards of CE2 Carbon Capital, LLC, PLH Group, Inc. and Nesco Holdings, LP. Prior to founding Energy Capital Partners, Mr. Kimmelman spent 22 years with Goldman Sachs, starting in 1983 in the firm’s Pipeline and Utilities Department within the Investment Banking Division. He remained exclusively focused on the energy and utility sectors in the Investment Banking Division until 2002 when he transferred to the firm’s J. Aron commodity group. He was named a General Partner of the firm in 1996. From 2002 to 2005, Mr. Kimmelman played a leadership role at Goldman Sachs in building a power generation asset portfolio through the J. Aron commodity group. Mr. Kimmelman received a B.A. in Economics from Stanford University and an M.B.A. from the Wharton School at the University of Pennsylvania. Mr. Kimmelman’s experience as founder and Senior Partner of Energy Capital Partners and knowledge of the energy industry provide the board with extensive financial and business leadership.

Thomas Lane.    Mr. Lane has been a member of the board of directors of our general partner since October 2014. Mr. Lane is also a Partner of Energy Capital Partners. He is involved in all areas of the firm’s investment activities, with a particular emphasis on the midstream sector. Mr. Lane serves on the boards of Summit Midstream Partners, LLC and Summit Midstream Partners, L.P. (NYSE: SMLP). Prior to realization, Mr. Lane served on the board of FirstLight Power Enterprises, Inc. and Cardinal Gas Storage Partners, LLC. Prior to joining Energy Capital Partners in 2005, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and midstream gas companies throughout the United States. Mr. Lane received a B.A. in Economics from Wheaton College and an M.B.A. from the University of Chicago. Mr. Lane provides the board with broad knowledge of the energy industry in addition to his financial, business and leadership expertise.

Jane O’Hagan.     Ms. Jane O’Hagan has been a member of the board of directors of our general partner since October 2014. Ms. O’Hagan is an independent director of our general partner and serves as Chairman of our conflicts committee and as a member of our audit committee. Ms. O’Hagan most recently served as the Chief Marketing Officer and Executive Vice President of Canadian Pacific Railway Limited (“CP Rail”) and of Canadian Pacific Railway Company from December 2011 to May 2014. Ms. O’Hagan served as the Senior Vice President of Marketing and Sales

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of CP Rail from April 2010 to December 2011 and also served as its Senior Vice President of Strategy & Yield from November 2008 to December 2009. She served as a Vice President of Strategy and External Affairs of CP Rail from 2005 to 2008 and also served as its Vice-President of Strategy Research and New Market Development and Assistant Vice-President, Strategy and Research from 2002 to 2005. Ms. O’Hagan has worked at CP Rail since 2002. Prior to her roles at CP Rail, Ms. O’Hagan was the Principal Health Care Consultant for Organomics, Inc. from 2001 to 2002. Prior to her role at Organomics, Ms. O’Hagan was a Consultant and Vice President of Strategy & Business Development at the Greater Baltimore Medical Center from 1995 to 2001. Ms. O’Hagan serves as a board member of Descartes System Group of Waterloo, Ontario. She recently served as a Director and Joint Chair of Lanzhou Pacific Logistics in Beijing, China, the first Sino-foreign railway joint venture logistics enterprise invested in by CP Rail and the China Railway Container Transport Co., Ltd. Ms. O’Hagan also represented CP Rail on the Province of British Columbia’s Asia Pacific Gateway Executive Council from 2004 until May 2014. In December 2012, Ms. O’Hagan was named one of Canada’s 2012 Top 100 Most Powerful Women by the Women Executive Network, an organization dedicated to recognizing the achievements of women who hold senior positions in Canada’s corporate community. Ms. O’Hagan holds a Bachelor of Arts (Hons.) and a Bachelor of Administrative and Commercial Studies from the University of Western Ontario. We believe Ms. O’Hagan’s extensive experience in the rail industry qualifies her to be a member of the board.

Brad Sanders.    Mr. Sanders has been a member of the board of directors of our general partner since October 2014. Mr. Sanders has also been Executive Vice President and Head of Market Strategy for USD since May 2014. Mr. Sanders’ main focus at USD is working with the leadership team to identify, develop and execute strategic commercial and market opportunities. Prior to USD, Mr. Sanders spent 32 years at Koch Industries where he was primarily responsible for building and managing several of Koch’s global trading businesses, including businesses in the crude oil, NGLs, distillates, gasoline and gasoline components, and plastics value chains. He is a 1979 Graduate of University of Kansas with a degree in business. He is a current Trustee for KU Endowment, and a current member for the KU Endowment Investment Committee. Mr. Sanders provides the board with strategic planning and business development leadership and expertise in the energy industry.

Jeff Wood. Mr. Wood has been a member of the board of directors of our general partner since January 2015, and serves as chairman of the audit committee and as a member of the conflicts committee. Mr. Wood also currently serves as the Executive Vice President and Chief Financial Officer of Siluria Technologies, Inc., a private energy technology company backed by a group of leading venture capital and private equity investors. Before joining Siluria, Mr. Wood served as Senior Vice President and Chief Financial Officer of Eagle Rock Energy Partners, LP, a publicly-traded master limited partnership (MLP) from 2009 through 2014. Prior to that, Mr. Wood was one of the founding principals of the Lehman Brothers’ MLP Investment Fund, which focused on direct investments in the MLP sector. He also spent 10 years with the Natural Resources Investment Banking team at Lehman Brothers where he primarily focused on MLP transactions. Mr. Wood began his career at Price Waterhouse in its audit and compliance practice. Mr. Wood brings a wide range of experience in finance and corporate governance to the board of directors of our general partner in addition to MLP and energy industry experience.

Board Leadership Structure

The chief executive officer of our general partner serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by USD. Accordingly, unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Energy Capital Partners Investment in USD

On September 19, 2014, Energy Capital Partners made a significant investment in USD, and indicated an intention to invest over 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. In connection with Energy Capital Partners’ investment, USD repurchased a substantial portion of Goldman Sachs’ investment in USD and will use the remaining proceeds to fund

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several existing growth projects and strengthen its balance sheet to allow for additional flexibility to pursue its goal of providing rail-related energy infrastructure solutions.

Special Approval Rights of Energy Capital Partners

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 any of the following actions (or take or agree to take any action that is reasonably likely to require or result in any of the following actions) without the affirmative vote of Energy Capital Partners (or, with respect to distributions by us or our subsidiaries, the members of our general partner’s board of directors appointed by Energy Capital Partners):

• any sale of USD, any subsidiary of USD, including us, or any of their assets (other than asset sales in the ordinary course of business), including by way of merger, consolidation, public offering or otherwise, other than to USD or a wholly owned subsidiary of USD;

• (A) any capital contribution or issuance of or redemption of securities of USD or any subsidiary of USD, including us, (B) any issuance of profits interests in USD, (C) any distributions, except distributions by us and our subsidiaries (which distributions shall be subject to the affirmative vote of the members of our general partner’s board of directors appointed by Energy Capital Partners), (D) any incurrence or refinancing of indebtedness (whether directly, through a guaranty or otherwise) outside of the ordinary course of business, other than any incurrence or refinancing of indebtedness by us or our subsidiaries (which incurrences and refinancings shall be subject to the affirmative vote of the members of our general partner’s board of directors appointed by Energy Capital Partners), (E) any acquisition of securities of any other entity in excess of the lesser of the consolidated earnings before interest, taxes, depreciation and amortization of USD Group LLC or $50 million or (F) any making of any loan or advance to any entity other than a wholly owned subsidiary of USD;

• the approval, modification or revocation of any budget or a material deviation from or a material expenditure not part of any such budget (including any material change with respect to the nature of any budgeted capital expenditure), other than the approval, modification or revocation of any budget related to us or our subsidiaries (which approvals, modifications or revocations shall be subject to the affirmative vote of the members of our general partner’s board of directors appointed by Energy Capital Partners);

• (A) amending the organizational documents of USD in a manner adverse to the holders of the common membership interests of USD, (B) amending the organizational documents of any subsidiary of USD, including us, (C) expanding the purpose of any of USD or any of its subsidiaries, including us, (D) causing or taking any action with the purpose or effect of causing the bankruptcy, liquidation, dissolution or winding up of USD or any of its subsidiaries, (E) making any material change to USD or any of its subsidiaries’ federal tax treatment, (F) entering into or amending any transaction with any member of USD or their affiliates or (G) creating or materially amending any employee incentive plan; or

• the determination of significant regulatory issues or litigation, including any decision to initiate, forego or settle any material litigation or arbitration, or the entering into discussions, or negotiations, with any governmental authority in connection with any investigation, proceedings or threatened investigation or proceedings, or any material inquiry.

Energy Capital Partners’ Right to Sell USD or Its Interests in USD

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.

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Board Role in Risk Oversight

Our corporate governance guidelines provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies that management has implemented to monitor such exposures.

Communication with the Board of Directors

A holder of our common units or other interested party who wishes to communicate with the non-management directors or independent directors of our general partner may do so by writing to: Independent Directors, c/o General Counsel, USD Partners GP LLC, at 811 Main Street, Suite 2800, Houston, Texas 77002. Communications will be relayed to the intended recipient of the board of directors except in instances where it is deemed unnecessary or inappropriate to do so. Any communications withheld will nonetheless be recorded and available for any director who wishes to review them.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act requires our directors, executive officers and 10% beneficial owners to file with the SEC reports of ownership and changes in ownership of our equity securities and to furnish us with copies of all reports filed. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner's officers, directors and greater than 10% unitholders under Section 16(a) were satisfied during the year ended December 31, 2014.

CODE OF BUSINESS CONDUCT AND ETHICS AND CORPORATE GOVERNANCE GUIDELINES

We have adopted a Code of Business Conduct and Ethics applicable to the directors and senior officers of our general partner including the principal executive officer, principal financial officer and principal accounting officer of USD Partners GP LLC. A copy of the Code of Business Conduct and Ethics is available on our website at www.usdpartners.com. We post on our website any amendments to or waivers of our Code of Business Conduct and Ethics and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to this information through such postings. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o USD Partners GP LLC, 811 Main Street, Suite 2800, Houston, Texas 77002.

We also have a statement of Corporate Governance Guidelines that sets forth the expectation of how our board of directors should function and its position with respect to key corporate governance issues. A copy of the Corporate Governance Guidelines is available on our website at www.usdpartners.com. We post on our website any amendments to our Corporate Governance Guidelines, and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to these amendments through such postings. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o USD Partners GP LLC, 811 Main Street, Suite 2800, Houston, Texas 77002.

AUDIT COMMITTEE

Our general partner has an audit committee currently comprised of two board members, Jeff Wood and Jane O’Hagan, who are independent as the term is used in Section 10A of the Exchange Act, and are not relying upon any exemptions from the foregoing independence requirements. Our general partner is relying on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter.

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Our general partner will appoint a third member to the audit committee within one year following the effective date of the registration statement on Form S-1 related to our IPO.

The audit committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the report of the independent registered public accounting firm. Our audit committee also has the sole authority for retaining and terminating our independent registered public accounting firm, approving all auditing services and related fees and the terms thereof, and pre-approving any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to our audit committee.

The charter of the audit committee is available on our website at www.usdpartners.com. The charter of the audit committee complies with the listing standards of the NYSE currently applicable to us. This material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o USD Partners GP LLC, 811 Main Street, Suite 2800, Houston, Texas 77002.

The board of directors of our general partner has determined that Jeff Wood qualifies as an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of Regulation S-K and are independent as defined by Section 303A of the listing standards of the NYSE.

The audit committee of our general partner has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our audit committee may do so by writing to the Chairman, Audit Committee, c/o USD Partners GP LLC, 811 Main Street, Suite 2800, Houston, Texas 77002.

CONFLICTS COMMITTEE

Our general partner has established a conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The conflicts committee will be comprised of at least two members of the board of directors of our general partner. Jane O’Hagan and Jeff Wood currently serve as members of the conflicts committee. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our incentive compensation plan. We anticipate that once appointed to our general partner’s board of directors, the additional independent members appointed to our audit committee will also serve on the conflicts committee. Any matters approved by our conflicts committee will be presumed to have been approved in good faith, will be deemed to be approved by all of our partners and will not be a breach by our general partner of any duties it may owe us or our unitholders.

The charter of the conflicts committee is available on our website at www.usdpartners.com. This material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o USD Partners GP LLC, 811 Main Street, Suite 2800, Houston, Texas 77002.

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Item 11. Executive Compensation

General

We and our general partner were formed in June 2014 and did not pay or accrue any obligations with respect to compensation for directors or officers for the 2013 fiscal year or for any prior period. In addition, we do not directly employ any of the persons responsible for managing our business. Our general partner, under the direction of its board of directors, is responsible for managing our operations and for obtaining the services of the employees that operate our business. However, we sometimes refer to the employees and officers of our general partner as our employees and officers in this report.

As an "emerging growth company," ("EGC"), as defined under the applicable rules of the SEC, we are not required to include a Compensation Discussion and Analysis section and have elected to comply with the scaled disclosure requirements applicable to EGCs. This executive compensation disclosure provides an overview of the executive compensation paid to the named executive officers, or NEOs, identified below for their services to us in 2014. For 2014, we determined the NEOs to be as follows:

• Dan Borgen, Principal Executive Officer and Director

• Adam Altsuler, Principal Financial Officer

• Guillermo Sierra, Vice President, Chief Strategy Officer and Head of M&A

For 2014 and all prior periods, all of the individuals who served as executive officers of our business were employed by USD or its affiliates other than us and, in addition to their responsibilities related to our business, also performed services for USD that were unrelated to us. Except with respect to our Class A units and with respect to awards that may be granted under our USD Partners LP 2014 Long-Term Incentive Plan ("LTIP"), all responsibility and authority for compensation-related decisions for the NEOs remains with USD and its affiliates, and such decisions are not subject to any approval by us, our general partner’s board of directors or any committees thereof. Other than the Class A units or awards that may be granted under the LTIP, USD and its affiliates have the ultimate decision-making authority with respect to the total compensation of their and their subsidiaries’ executive officers and their employees. Except with respect to the Class A units and awards that may be granted under the LTIP, we incur only a fixed annual cash charge for the services rendered to us and our general partner by the NEO’s, the amount of which is set under the terms of the omnibus agreement.

Summary Compensation Table

The following table summarizes total compensation for services rendered to us by the NEOs during 2014. All of our NEOs provide services to both us and USD and its affiliates other than us. Cash amounts paid for services to us (which amounts are shown in the “Salary” column of the table below) are limited to the fixed fees that we pay to USD for the services of each of the NEOs under the terms of the omnibus agreement. The NEOs also received other compensation from USD for services unrelated to us.

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SUMMARY COMPENSATION TABLE

Name and Principal Position		Salary (1)		Stock Awards(2)		Total
	Year	($)		($)		($)
Dan Borgen	2014	$	25,916	$	1,414,200	$	1,440,116
Principal Executive Officer and Director
Adam Altsuler	2014	$	51,059	$	514,255	$	565,314
Principal Financial Officer
Guillermo Sierra	2014	$	34,686	$	899,946	$	934,632
Vice President, Chief Strategy Officer and Head of M&A

⁽¹⁾ The amounts presented reflect the portion of the fixed fee that we pay to USD for the NEOs' services under Schedule C of the omnibus agreement, prorated based on the number of days between the October 15, 2014 effective date of the omnibus agreement and December 31, 2014, (i.e., 78 days).

⁽²⁾ The amounts presented reflect the grant date fair value of the Class A unit awards, as determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, based on the probable outcome with respect to performance, which assumes positive growth in our annualized distributions resulting in conversion of each vesting tranche of the Class A units into common units at a ratio of one-for-one. Assuming maximum performance achievement (i.e., growth in our annualized distributions of greater than or equal to 10%) for all vesting tranches of Class A units, then the value would be 162.5% of the amounts shown. For additional information, please refer to the discussion below under the heading “Class A unit Awards.”

Narrative Disclosure to Summary Compensation Table

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act. We completed our IPO on October 15, 2014. Neither we nor our general partner has accrued any financial obligations related to the compensation for our executive officers, or other personnel, for any periods prior to our IPO. Therefore, the amounts shown in the Summary Compensation Table above reflect only compensation amounts allocated to us with respect to services provided from and after the date of our IPO.

Neither we, our general partner, nor any of our subsidiaries have employees. USD is contractually obligated to provide its and its subsidiaries’ employees and other personnel necessary to conduct our operations. This includes all of our executive officers. The executive officer compensation is paid by USD or its applicable affiliate. We pay USD a fixed amount each month for the services of our executive officers.

Our general partner’s board of directors has adopted the LTIP on our behalf. Certain officers, employees, consultants and non-management directors of our general partner and its affiliates who make significant contributions to our business are eligible to receive awards under the LTIP. Awards under the LTIP will be approved by our general partner’s board of directors. As of December 31, 2014, no awards had yet been made under our LTIP.

Prior to our IPO, our general partner also granted Class A units in us to our NEOs and certain other key employees as described below.

Class A Unit Awards

In August 2014, our general partner’s board of directors granted Class A unit awards to our NEOs as follows: Mr. Borgen - 55,000 Class A units, Mr. Altsuler - 20,000 Class A units and Mr. Sierra - 35,000 Class A units. The Class A units are limited partner interests in our partnership that entitle the holder to distributions that are equivalent to the distributions paid in respect of our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters). The Class A units will vest in four equal annual installments over a four-year period (each of which we refer to as a Class A Vesting Tranche), subject to us growing our annualized distributions each year. If we do not achieve positive distribution growth in any of these years, the Class A units in the Class A Vesting Tranche that

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would otherwise vest for that year will be forfeited. The Class A units are also subject to vesting acceleration in certain circumstances. For more information about vesting acceleration of the Class A units, see the discussion below under the heading “-Potential Payments Upon Termination or Change in Control.”

The Class A units will convert into our common units upon vesting of the Class A units. The number of common units into which the Class A units will convert upon vesting is tied to the level of our distribution growth for the applicable year. If the Class A units in a Class A Vesting Tranche vest but we grow our annualized distribution by less than 10%, the Class A units in that Class A Vesting Tranche will convert into common units one-for-one. If we grow our annualized distribution by 10% or more, the Class A units in that Class A Vesting Tranche will convert into common units based on a conversion factor of 1.25 for the first Class A Vesting Tranche, 1.5 for the second Class A Vesting Tranche, 1.75 for the third Class A Vesting Tranche and 2.0 for the last Class A Vesting Tranche.

Outstanding Equity Awards at Fiscal Year-End 2014

The following table shows outstanding equity awards for our NEOs. All values are shown as of December 31, 2014.

	Unit Awards - Class A units
Name	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (1) (#)	Equity Incentive Plan Awards: Market or Payout of Value of Unearned Shares, Units or Other Rights That Have Not Vested(2) ($)
Dan Borgen	55,000	764,500
Adam Altsuler	20,000	278,000
Guillermo Sierra	35,000	486,500

⁽¹⁾  The Class A units were granted on August 18, 2014, and vest in four equal annual installments (with the first installment vesting on the first business day following the making of our regular quarterly distribution in respect of the calendar quarter ended December 31, 2015), subject to continued employment and to us achieving the distribution growth required for the applicable installment to vest. For additional information, please refer to the discussion above under the heading “Class A unit Awards.”

⁽²⁾  The fair value is based on the closing market price of a common unit on December 31, 2014, of $13.90 per unit. The amounts shown assume that the Class A units would convert into our common units at a ratio of one-for-one.

Potential Payments Upon Termination or Change in Control

None of our NEOs have entered into any employment, severance or similar agreements in relation to their services to us or our general partner and, except with respect to the Class A units, as of December 31, 2014, there were no arrangements pursuant to which our NEOs would receive any payments or benefits in connection with a change in control of us.

The terms of the Class A units that were granted to our NEOs provide that if (i) the executive’s employment is terminated without cause or due to his death or disability, (ii) the executive resigns his employment for good reason or (iii) there is a change in control of our partnership, the Class A units will fully vest and convert into common units based on the maximum conversion factor that could have applied to such Class A units. For additional information, please refer to the discussion above under the heading “Class A unit Awards.”

“Cause” when defined for purposes of the Class A units generally means (i) an act of gross negligence or willful misconduct that adversely affects USD or its affiliates, (ii) an act of fraud, theft or embezzlement, (iii) a conviction of or guilty or nolo contendere plea with respect to certain crimes, (iv) a breach of applicable material policies or agreements or (v) the refusal to perform reasonable duties following notice and opportunity to cure. “Good reason” for purposes of the Class A units is generally defined as (x) a material diminution in duties or responsibilities, (y) a material diminution

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in base salary or (z) a relocation of principal place of employment by more than 50 miles, in each case subject to a notice and cure right for us or our affiliates.

2014 Director Compensation Table

As a partnership, we are managed by our general partner. The members of the board of directors of our general partner perform for us the functions of a board of directors of a business corporation. We are allocated 100% of the director compensation of these board members. Our general partner has implemented a director compensation policy for members of the board of directors who are not officers, employees or paid consultants or advisors of us or our general partner or USD or Energy Capital Partners. Such directors are expected to receive an annual compensation package valued at approximately $200,000. One-third of this amount is expected to be paid in the form of a cash retainer and the remaining two-thirds is expected to be provided in the form of a unit based award (with distribution equivalent rights) under the USD Partners LP 2014 Long-Term Incentive Plan. However, no grants of unit based awards were made to any of these directors in 2014 under the LTIP. Such directors will also receive reimbursement for out-of-pocket expenses associated with attending board or committee meetings and director and officer liability insurance coverage. Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as directors. All directors are indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law and are reimbursed for all expenses incurred in attending to his or her duties as a director.

DIRECTOR COMPENSATION

Name	Fees Earned or Paid in Cash (1)($)	Unit Awards ($)	Total ($)
Jane O'Hagan	15,232	—	15,232

⁽¹⁾  Ms. O'Hagan was elected in October 2014, and the amount presented represents the director cash retainer payments made in 2014.

Compensation Committee Report

As our general partner does not have a compensation committee, the board of directors of our general partner provides the oversight, administers and makes decisions regarding our compensation policies and plans. Additionally, the board of directors of our general partner generally reviews and discusses the Compensation Discussion and Analysis with senior management of our general partner as a part of our governance practices. Based on this review and discussion, the board of directors of our general partner has directed that the Compensation Discussion and Analysis be included in this report for filing with the SEC.

Members of the Board of Directors of USD Partners GP LLC
Dan Borgen	Mike Curry
Sara Graziano	Douglas Kimmelman
Thomas Lane	Jane O'Hagan
Brad Sanders	Jeff Wood

Compensation Committee Interlocks and Insider Participation

As discussed above, the board of directors of our general partner is not required to maintain, and does not maintain a compensation committee.

Mr. Borgen, who serves on the board of directors of our general partner, participated in his capacity as a director in the deliberations of the board of directors of our general partner concerning executive officer compensation. In addition, Mr. Borgen makes recommendations to the board of directors of our general partner regarding named executive

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officer compensation. Mr. Borgen abstains from any decision regarding his own compensation as an officer of our general partner.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following tables set forth information with respect to persons known to us to be the beneficial owners of more than 5% of any class of our units and NEOs, directors and executive officers of USD Partners GP LLC as a group. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. The percentage of units beneficially owned is based on a total of 10,213,545 common units, 220,000 Class A units and 10,463,545 subordinated units outstanding. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of March 24, 2015, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table sets forth information as of March 24, 2015, with respect to persons, other than the NEOs, directors and executive officers of USD Partners GP LLC as a group, known to us to be the beneficial owners of more than 5% of any class of our units:

Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common Units, Class A Units and Subordinated Units Beneficially Owned
US Development Group LLC (2)	1,093,545	10.7	%	10,463,545	100.0	%	55.3	%
USD Holdings LLC (3)	497,503	4.9	%	4,760,338	45.5	%	25.1	%
Energy Capital Partners III-A (4)(5)	259,561	2.5	%	2,483,607	23.7	%	13.1	%
Energy Capital Partners III-B (USD IP) (4)(5)	163,781	1.6	%	1,567,137	15.0	%	8.3	%
Energy Capital Partners III-C (USD IP) (4)(5)	107,307	1.1	%	1,026,762	9.8	%	5.4	%
Piper Jaffray Companies (6)	1,141,772	11.2	%	—	—		5.5	%
Kayne Anderson Capital Advisors, L.P. (7)	3,400,461	33.3	%	—	—		16.3	%
Oppenheimer Funds, Inc. (8)	652,810	6.4	%	—	—		3.1	%

⁽¹⁾ Unless otherwise indicated, the address for each beneficial owner is 811 Main Street, Suite 2800, Houston, Texas 77002.

⁽²⁾ USD, through its 100% ownership of USD Group LLC (which owns 100% of our general partner), is the indirect owner of 1,093,545 common units, 10,463,545 subordinated units and 427,503 general partner units. USD is the parent company of USD Group LLC who holds the common units and subordinated units directly and is the sole owner of the member interests of our general partner. USD Group LLC is managed by USD. USD is managed by a seven person board of directors that includes Dan Borgen, Mike Curry, James Hutson-Wiley, Sara Graziano, Douglas Kimmelman, Thomas Lane and Alan Crown. The board of directors of USD exercises voting and dispositive power over the units held by USD Group LLC , and acts by majority vote. Please read Item 13. Certain Relationships and Related Transactions, and Director Independence. Ms. Graziano and Messrs. Borgen, Curry, Hutson-Wiley, Kimmelman, Lane and Crown are thus not deemed to have beneficial ownership of the units owned by USD Group LLC.

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⁽³⁾  USD Holdings, LLC is a 45.5% member of USD and may therefore be deemed to indirectly beneficially own 497,503 common units, 4,760,338 subordinated units and 194,323 general partner units held by USD. As holders of a 45.5% voting interest of USD, USD Holdings, LLC is entitled to elect three directors of USD. USD Holdings LLC is managed by its managers, Mike Curry, Dan Borgen and James Hutson-Wiley. Neither Messrs. Curry, Borgen nor Hutson-Wiley are deemed to beneficially own, and they disclaim beneficial ownership of, any common units or subordinated units beneficially owned by our general partner or USD.

⁽⁴⁾  The address for this beneficial owner or entity is 51 John F. Kennedy Parkway, Suite 200, Short Hills, New Jersey 07078.

⁽⁵⁾  The Energy Capital Partners funds are members of USD, collectively holding a 49.2% interest in USD, and may therefore be deemed to indirectly collectively beneficially own 538,361 common units, 5,151,284 subordinated units and 194,323 general partner units held by USD. Energy Capital Partners III, LLC is the direct or indirect general partner of each of the Energy Capital Partners funds and is deemed to indirectly beneficially own the securities held by the Energy Capital Partners funds, but disclaims such ownership except to the extent of its pecuniary interest therein. As holders of a 49.2% voting interest of USD, the Energy Capital Partners funds are entitled to elect three directors of USD and have veto rights over certain actions by USD and its subsidiaries. Douglas Kimmelman, Thomas Lane and Sara Graziano are each a member of the board of directors of our general partner as representatives of Energy Capital Partners. In addition, Mr. Kimmelman is a managing member and partner, and Mr. Lane is a managing member and partner, at Energy Capital Partners III, LLC, the general partner of the general partner of the Energy Capital Partners funds. None of Mr. Kimmelman, Mr. Lane nor Ms. Graziano are deemed to beneficially own, and they disclaim beneficial ownership of, any common units or subordinated units beneficially owned by our general partner or USD.

⁽⁶⁾  Based solely on a Schedule 13G/A filed by Piper Jaffray Companies on February 17, 2015. The Schedule 13G/A states that Piper Jaffray Companies has shared voting and dispositive power over 260,135 of the common units. The Schedule 13G/A states that Advisory Research, Inc. (“ARI”), 180 N. Stetson, Chicago, IL 60601, a wholly-owned subsidiary of Piper Jaffray Companies and an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of the 1,141,772 common units as a result of acting as investment adviser to various clients. The Schedule 13G/A states that Piper Jaffray Companies may be deemed to be the beneficial owner of these 1,141,772 common units through control of ARI. However, Piper Jaffray Companies disclaims beneficial ownership of such common units. The address of the Piper Jaffray Companies is 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067.

⁽⁷⁾  Based solely on a Schedule 13G/A filed by Kayne Anderson Capital Advisors, L.P. on January 12, 2015. The Schedule 13G/A states that Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power over the 3,400,461 common units. The Schedule 13G/A states that the reported common units are owned by investment accounts (investment limited partnerships, a registered investment company and institutional accounts) managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment adviser. Kayne Anderson Capital Advisors, L.P. is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the common units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and his ownership of common stock of the registered investment company. The address of Kayne Anderson Capital Advisors, L.P. is 800 Nicollet Mall, Suite 1000, Mail Stop J09S02, Minneapolis, Minnesota 55402.

⁽⁸⁾ Based solely on a Schedule 13G filed by OppenheimerFunds, Inc. on February 2, 2015. The Schedule 13G states that OppenheimerFunds, Inc. shares voting and dispositive power over the 642,810 common units. The Schedule 13G states that Oppenheimer SteelPath MLP Income Fund beneficially owns and has sole voting power and shared dispositive power over 639,975 of the common units. The Schedule 13G states that OppenheimerFunds, Inc. is an investment adviser in accordance with Rule 13d-1(b)(1)(ii)(E) and Oppenheimer SteelPath MLP Income Fund is an investment company registered under section 8 of the Investment Company Act of 1940. OppenheimerFunds, Inc. disclaims beneficial ownership of the 642,810 common units. The address of OppenheimberFunds, Inc. Two

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World Financial Center, 225 Liberty Street, New York, NY 10281 and the address of Oppenheimer SteelPath MLP Income Fund is 6803 S. Tucson Way Centennial, CO 80112.

SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS

The following table sets forth information as of March 24, 2015, with respect to each class of our units beneficially owned by the NEOs, directors and executive officers of USD Partners GP LLC as a group:

Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Class A Units Beneficially Owned	Percentage of Class A Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned	Percentage of Total Common Units, Class A Units and Subordinated Units Beneficially Owned
Dan Borgen (2)	28,000	*		55,000	23.9	%	—	*
Adam Altsuler (3)	200	*		20,000	8.7	%	—	*
Guillermo Sierra (4)	7,500	*		35,000	15.2	%	—	*
Mike Curry (5)	8,000	*		—	—		—	*
Sara Graziano	3,500	*		—	—		—	*
Douglas Kimmelman	50,000	*		—	—		—	*
Thomas Lane	50,000	*		—	—		—	*
Jane O'Hagan (6)	—	—		—	—		—	*
Jeff Wood (7)	1,300	*		—	—		—	*
Brad Sanders (8)	125,000	1.2	%	40,000	17.4	%	—	*
All Directors and Executive Officers as a group (13 Persons) (9)	283,500	2.8	%	180,000	78.3	%	—	2.2	%

* Less than 1.0%.

⁽¹⁾  Unless otherwise indicated, the address for each beneficial owner is 811 Main Street, Suite 2800, Houston, Texas 77002.

⁽²⁾  Excludes 31,308 phantom units granted under the 2014 USD Partners LP Long-Term Incentive Plan (the "LTIP"). The phantom units will vest in four equal annual installments commencing on February 16, 2016.

⁽³⁾  Excludes 12,127 phantom units granted under the LTIP. The phantom units will vest in four equal annual installments commencing on February 16, 2016.

⁽⁴⁾  Excludes 15,468 phantom units granted under the LTIP. The phantom units will vest in four equal annual installments commencing on February 16, 2016.

⁽⁵⁾  Excludes 19,799 phantom units granted under the LTIP. The phantom units will vest in four equal annual installments commencing on February 16, 2016.

⁽⁶⁾  Excludes 10,256 phantom units granted under the LTIP. The phantom units will vest on February 16, 2016.

⁽⁷⁾  Excludes 10,256 phantom units granted under the LTIP. The phantom units will vest on February 16, 2016.

⁽⁸⁾  Excludes 45,372 phantom units granted under the LTIP. The phantom units will vest in four equal annual installments commencing on February 16, 2016.

⁽⁹⁾  Excludes 188,381 phantom units granted under the LTIP.

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SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table provides information as of December 31, 2014 with respect to common units that may be issued under the LTIP:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(1)	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans(2)
Equity compensation plans approved by security holders	N/A	N/A	1,654,167
Equity compensation plans not approved by security holders	______	______	______
Total			1,654,167

⁽¹⁾  We have not previously granted equity incentive awards in us to any person pursuant to the LTIP.

⁽²⁾  Reflects the common units available for issuance pursuant to the LTIP.

Item 13. Certain Relationships and Related Transactions, and Director Independence

As of March 24, 2015, USD Group LLC owns 11,557,090 common units and subordinated units representing an aggregate 54.2% limited partner interest. In addition, as of March 24, 2015 our general partner owns 427,083 general partner units representing a 2.0% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of USD Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates prior to or in connection with our IPO for the contribution of the assets and liabilities to us:	1,093,545 common units;
	10,463,545 subordinated units;
	427,083 general partner units representing a 2.0% general partner interest in us;
	the incentive distribution rights; and
	$100.0 million cash distribution of the net proceeds from borrowings under our Term Loan Facility and reimbursement of USD Group LLC of $7.5 million for fees and expenses related to our IPO.

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Operational Stage

Distributions of available cash to our general partner and its affiliates	We generally make cash distributions of 98.0% to the unitholders pro rata, including USD Group LLC, as holder of an aggregate of 1,093,545 common units and 10,463,545 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner entitles USD Group LLC to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level.
	Additionally, certain executive officers and other key employees of our general partner and its affiliates who provide services to us own 220,000 Class A units and 415,608 phantom units that may be convertible into our common units if certain vesting conditions are met.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, USD Group LLC, our general partner and their affiliates would receive an annual distribution of approximately $0.5 million on the 2.0% general partner interest and $13.3 million on their common units and subordinated units.

Holders of our Class A units would receive an annualized distribution of approximately $0.3 million on their Class A units and holders of phantom units would receive an annualize distribtuion of approximately $0.5 million on their phantom units.

Payments to our general partner and its affiliates

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 and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we pay to USD Group LLC an annual fee for the provision of various centralized administrative services for our benefit. We will also reimburse USD Group LLC for any additional out-of-pocket costs and expenses incurred by USD Group LLC and its affiliates in providing general and administrative expenses associated with our terminals to us. For the year ending December 31, 2015, we estimate that these expenses, including the annual fee, will be approximately $4.9 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. Please read “—Agreements in Connection with Our Initial Public Offering—Omnibus Agreement” below.

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

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Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements in Connection with Our Initial Public Offering

We and other parties have entered into various agreements that effect the transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of our IPO. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with USD Group LLC are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid for with the proceeds of our IPO.

Omnibus Agreement

At the closing of our IPO, we entered into an omnibus agreement with USD and USD Group LLC, certain of our subsidiaries and our general partner that addresses the following matters:

• our payment of an annual amount to USD Group LLC, initially in the amount of approximately $4.9 million, for providing certain general and administrative services by USD Group LLC and its affiliates, which annual amount includes a fixed annual fee of $2.5 million for providing certain executive management services by certain officers of our general partner. Other portions of this annual amount are based on the costs actually incurred by USD Group LLC and its affiliates in providing the services;

• our right of first offer to acquire the Hardisty Phase II and Hardisty Phase III projects as well as other additional midstream infrastructure assets and businesses that USD and USD Group LLC may construct or acquire in the future;

• our obligation to reimburse USD Group LLC for any out-of-pocket costs and expenses incurred by USD Group LLC in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement), as well as any other out-of-pocket expenses incurred by USD Group LLC on our behalf;

• an indemnity by USD Group LLC for certain environmental and other liabilities, and our obligation to indemnify USD Group LLC and its subsidiaries for events and conditions associated with the operation of our assets that occur after the closing of our IPO and for environmental liabilities related to our assets to the extent USD Group LLC is not required to indemnify us; and

• so long as USD Group LLC controls our general partner, the omnibus agreement will remain in full force and effect. If USD Group LLC ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of Annual Fee and Reimbursement of Expenses

We pay USD Group LLC, in equal monthly installments, the annual amount USD Group LLC estimates will be payable by us to USD Group LLC during that calendar year for providing services for our benefit. The omnibus agreement provides that this amount may be adjusted annually to reflect, among other things, changes in the scope of the general and administrative services provided to us due to a contribution, acquisition or disposition of assets by us or our subsidiaries or for changes in any law, rule or regulation applicable to us affecting the cost of providing the general and administrative services. We reimburse USD Group LLC for any out-of-pocket costs and expenses incurred by USD Group LLC in providing general and administrative services to us. This reimbursement is in addition to our

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reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Right of First Offer

Under the omnibus agreement, until the 7th anniversary of the closing of our IPO, prior to engaging in any negotiation regarding the sale, transfer or disposition of (i) the Hardisty Phase II project, (ii) the Hardisty Phase III project or (iii) any other midstream infrastructure assets and business that USD or USD Group LLC may develop, construct or acquire, USD or USD Group LLC will deliver a written notice to us setting forth the material terms and conditions upon which USD or USD Group LLC would sell or transfer such assets or businesses to us. Following the receipt of such notice, we will have 60 days to determine whether the asset is suitable for our business at that particular time, and to propose a transaction with USD or USD Group LLC. We and USD or USD Group LLC will then have 60 days to negotiate in good faith to reach an agreement on such transaction. If we and USD or USD Group LLC, as applicable, are unable to agree on such terms during such 60-day period, then USD or USD Group LLC, as applicable, may transfer such asset to any third party during a 180-day period following the expiration of such 60-day period on terms generally no less favorable to the third party than those included in the written notice.

Our decision to make any offer will require the approval of the conflicts committee of the board of directors of our general partner. The consummation and timing of any acquisition by us of the assets covered by our right of first offer will depend on, among other things, USD or USD Group LLC’s decision to sell an asset covered by our right of first offer, our ability to reach an agreement with USD or USD Group LLC on price and other terms and our ability to obtain financing on acceptable terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and USD or USD Group LLC are 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 read Item 10. Directors, Executive Officers and Corporate Governance—Special Approval Rights of Energy Capital Partners.

Indemnification

Under the omnibus agreement, USD Group LLC indemnifies us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before the closing of our IPO. Indemnification for any unknown environmental liabilities is limited to liabilities due to occurrences on or before the closing of our IPO and identified prior to the third anniversary of the closing of our IPO, and is subject to an aggregate deductible of $500,000 before we are entitled to indemnification. There is a $10.0 million cap on the amount for which USD Group LLC indemnifies us under the omnibus agreement with respect to environmental claims once we meet the deductible, if applicable. USD Group LLC also indemnifies us for certain defects in title to the assets contributed to us and failure to obtain certain consents, licenses and permits necessary to conduct our business, including the cost of curing any such condition and certain tax liabilities attributable to the operation of the assets contributed to us prior to the time they were contributed.

USD Group LLC also indemnifies us for liabilities, subject to an aggregate deductible of $500,000, relating to:

• the assets contributed to us, other than environmental liabilities, that arose out of the ownership or operation of the assets prior to the closing of our IPO and that are asserted prior to the third anniversary of the closing of our IPO;

• events and conditions associated with any assets retained by USD Group LLC; and

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• all tax liabilities attributable to the assets contributed to us arising prior to the closing of our IPO or otherwise related to USD Group LLC’s contribution of those assets to us in connection with our IPO.

Contribution Agreement

In connection with the closing of the IPO, we entered into a contribution, conveyance and assumption agreement ("Contribution Agreement") with USD and certain of its subsidiaries that effected the transfer to us of our initial assets, including the Hardisty rail terminal, West Colton rail terminal and San Antonio rail terminal and the use of net proceeds of the IPO. These transactions, among others, were made in a series of steps outlined in the Contribution Agreement.

Other Agreements with USD Group LLC and Related Parties

Terminal Services Agreement

We have entered into a terminal services agreement with USD Marketing LLC, a wholly owned subsidiary of USD Group LLC, to provide terminalling services at our Hardisty rail terminal. This agreement has an initial contract term of five years that commenced on October 1, 2014. The terms and conditions of this agreement are similar to the terms and conditions of third-party terminal services agreements at the Hardisty rail terminal. Please read Item 1. Business—Business Segments —Hardisty Rail Terminal The aggregate payment under this agreement will be approximately $40.0 million Canadian dollars over the agreement’s five-year term.

Purchase and Sale Agreement

In connection with our IPO, our subsidiary that owns the Hardisty rail terminal entered into a Purchase and Sale Agreement with a subsidiary of USD Group LLC pursuant to which:

• our subsidiary sold and transferred to USD Group LLC’s subsidiary approximately 320 acres of undeveloped land currently owned by our subsidiary and located immediately to the north of the Hardisty rail terminal;

• USD Group LLC’s subsidiary delivered to our subsidiary a note for the entire purchase price, the only condition for the payment obligations under the note being the transfer and conveyance of the undeveloped land from our subsidiary to USD Group LLC’s subsidiary, free and clear of all monetary liens and encumbrances. In connection with our IPO, our subsidiary distributed its interest in this note and the note is held by USD Group LLC;

• our subsidiary transferred and conveyed fee simple title to the undeveloped land to USD Group LLC’s subsidiary, free and clear of all monetary liens; and

• concurrently with the transfer and conveyance of the undeveloped land from our subsidiary to USD Group LLC’s subsidiary, our subsidiary and USD Group LLC’s subsidiary entered into the development rights and cooperation agreement described below.

Development Rights and Cooperation Agreement

In connection with the transfer and conveyance of the undeveloped land under the Purchase and Sale Agreement described above, our subsidiary that owns the Hardisty rail terminal entered into a Development Rights and Cooperation Agreement with USD Group pursuant to which:

• our subsidiary granted to USD Group LLC the right to develop, construct and operate certain aspects of the Hardisty Phase II and Phase III projects in, on, over, across and under the property on which the Hardisty rail terminal is located, including the exclusive right to develop and construct such expansions for a period of seven years after the closing of our IPO;

• our subsidiary granted to USD Group LLC the right to use (both on a temporary and permanent basis) certain portions of the property on which the Hardisty rail terminal is located in connection with the development, construction and operation of the Hardisty Phase II and Phase III projects;

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• our subsidiary will cooperate with USD Group LLC in connection with the development, construction and operation of the Phase II and Phase III projects;

• our subsidiary will enter into such further agreements or instruments with or for the benefit of USD Group LLC and any land owned by USD Group LLC (including the undeveloped land being acquired by USD Group LLC under the Purchase and Sale Agreement described above) and will grant further rights in, on, over, across and under the property on which the Hardisty rail terminal is located to or for the benefit of USD Group LLC and any land owned by USD Group LLC (including the undeveloped land being acquired by USD Group LLC under the Purchase and Sale Agreement described above), as USD Group LLC may reasonably request in connection with the Phase II and/or Phase III projects;

• both the Phase II and Phase III projects will be at the sole cost and expense of USD Group LLC, and will be subject to the observance by USD Group LLC of certain customary construction-related requirements and obligations; and

• all improvements constructed or installed by USD Group LLC in connection with the Phase II and/or Phase III projects will be owned by USD Group LLC and USD Group LLC will be entitled to grant liens on such improvements and/or in and to any rights acquired by USD Group LLC under the Development Rights and Cooperation Agreement.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including USD, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to USD. At the same time, our general partner has a duty to manage our partnership in a manner it believes is in our best interests. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

• approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or

• approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates, although our general partner is not obligated to seek such approval.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner takes or declines the course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third-party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of

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directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interests of the partnership. Please read Item 10. Directors, Executive Officers and Corporate Governance—Conflicts Committee for information about the conflicts committee of our general partner's board of directors.

REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

The board of directors of our general partner adopted a related party transactions policy in connection with the closing of our IPO that provides that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above was adopted in connection with the closing of our IPO, and as a result the transactions described above were not reviewed under such policy.

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Item 14. Principal Accountant Fees and Services

The following table sets forth the aggregate fees billed for professional services rendered by BDO USA, LLP("BDO"), our principal independent auditors from December 1, 2014, and UHY LLP ("UHY"), our principal independent auditors in 2014 until December 1, 2014, for each of the last two fiscal years.

	For the year ended December 31,
	2014				2013
	BDO		UHY		UHY
	(in millions)
Audit fees (1)	$	0.4	$	0.6	$	—
Audit-related fees (2)	—		—		—
Tax fees (3)	—		—		—
All other fees (4)	—		—		—
Total	$	0.4	$	0.6	$	—

⁽¹⁾  Audit fees consist of fees billed for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, audits of USD and various subsidiaries for statutory and regulatory filing requirements and our debt and equity offerings.

⁽²⁾  Audit-related fees represent fees for assurance and related services. Neither BDO nor UHY provided any audit-related services to us during the last two fiscal years.

⁽³⁾  Neither BDO nor UHY provided any tax services to us during the last two fiscal years.

⁽⁴⁾  All other fees represent fees for services not classifiable under the categories listed in the above table. No such services were rendered by BDO or UHY to us during the last two fiscal years.

Engagements for services provided by BDO are subject to pre-approval by the audit committee of the board of directors for USD Partners GP LLC. All services in 2014 were pre-approved by the audit committee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:

(1)    Financial Statements.

The following financial statements and supplementary data are incorporated by reference in Part II, Item 8. Financial Statements and Supplementary Data beginning on page 75 of this Annual Report.

a. Report of BDO USA, LLP, Independent Registered Public Accounting Firm.

b. Report of UHY LLP, Independent Registered Public Accounting Firm.

c. Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012.

d. Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014, 2013 and 2012.

e. Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012.

f. Consolidated Balance Sheets as of December 31, 2014 and 2013.

g. Consolidated Statements of Partners’ Capital for the years ended December 31, 2014, 2013 and 2012.

h. Notes to the Consolidated Financial Statements.

(2)    Financial Statement Schedules.

All schedules have been omitted because they are not applicable, the required information is shown in the consolidated financial statements or Notes thereto or the required information is immaterial.

(3)    Exhibits.

Reference is made to the “Index of Exhibits” following the signature page on page 140, which is hereby incorporated into this Item.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		USD PARTNERS LP (Registrant)
		By:	USD Partners GP LLC, its General Partner
Date:	March 30, 2015	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President

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POWER OF ATTORNEY

KNOW ALL BY THESE PRESENTS, that each of the undersigned officers and directors of USD Partners GP LLC, a Delaware limited liability company and general partner of USD Partners LP, a Delaware limited partnership (the "Registrant"), does hereby constitute and appoint Dan Borgen, Adam Altsuler and Keith Benson, and each of them, as his true and lawful attorney or attorneys-in-fact, with full power of substitution and revocation, for each of the undersigned and in the name, place, and stead of each of the undersigned, to sign on behalf of each of the undersigned any and all amendments to the Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith including, without limitation, a Form 12b-25 with the Securities and Exchange Commission, granting to said attorney or attorneys-in-fact, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorneys-in-fact or any of them or their substitute or their substitutes may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated.

Signature	Title	Date
/s/ Dan Borgen	Chairman of the Board, Chief Executive Officer and President	March 30, 2015
Dan Borgen
	(Principal Executive Officer)
/s/ Adam Altsuler	Vice President, Chief Financial Officer (Principal Financial Officer)	March 30, 2015
Adam Altsuler
/s/ Chris Robbins	Vice President, Chief Accounting Officer (Principal Accounting Officer)	March 30, 2015
Chris Robbins
/s/ Mike Curry	Director	March 30, 2015
Mike Curry
/s/ Sara Graziano	Director	March 30, 2015
Sara Graziano
/s/ Douglas Kimmelman	Director	March 30, 2015
Douglas Kimmelman
/s/ Thomas Lane	Director	March 30, 2015
Thomas Lane
/s/ Jane O'Hagan	Director	March 30, 2015
Jane O’Hagan
/s/ Jeff Wood	Director	March 30, 2015
Jeff Wood
/s/ Brad Sanders	Director	March 30, 2015
Brad Sanders

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Index of Exhibits

Each exhibit identified below is filed as a part of this Annual Report.

Exhibit Number	Description
3.1	Certificate of Limited Partnership of USD Partners LP (incorporated by reference herein to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-198500) filed on August 29, 2014, as amended).
3.2	Second Amended and Restated Agreement of Limited Partnership of USD Partners LP dated October 15, 2014, by and between USD Partners GP LLC and USD Group LLC (incorporated by reference herein to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
10.1	Contribution Conveyance and Assumption Agreement dated as of October 15, 2014, by and among U.S. Development Group, LLC, USD Group LLC, USD Partners GP LLC, USD Partners LP and USD Logistics Operations LP (incorporated by reference herein to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
10.2	Omnibus Agreement dated as of October 15, 2014, by and among U.S. Development Group, LLC, USD Group LLC, USD Partners GP LLC, USD Partners LP and USD Logistics Operations LP (incorporated by reference herein to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
10.3	Credit Agreement, dated as of October 15, 2014, among USD Partners LP and USD Terminals Canada ULC, as borrowers, Citibank, N.A., as administrative agent, swing line lender and l.c. issuer, U.S. Bank National Association, as an l/c issuer and the lenders from time to time party thereto (incorporated by reference herein to Exhibit 10.3 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
#10.4	USD Partners LP 2014 Long-Term Incentive Plan (incorporated by reference herein to Exhibit 10.4 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
10.5	Offer to Purchase and Agreement to Purchase and Sale, dated October 15, 2014 (incorporated by reference herein to Exhibit 10.5 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
10.6	Development Rights and Cooperation Agreement between USD Terminals Canada ULC, as Current Operator, and USD Terminals Canada II ULC, as Developer, dated as of October 16, 2014 (incorporated by reference herein to Exhibit 10.6 to the Current Report on Form 8-K (File No. 001-36674) filed on October 21, 2014).
#10.7	Form of USD Partners LP Long-Term Incentive Plan Phantom Unit Agreement (U.S.) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-36674) filed on February 20, 2015).
†10.10	Services Agreement Between USD Terminals Canada ULC and USD Marketing LLC, effective July 7, 2014 (incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-1 (File No. 333-1985) filed on August 29, 2014).
10.11	Facilities Connection Agreement Between USD Terminals Canada Inc. and Gibson Energy Partnership, dated June 4, 2013 (incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1 (File No. 333-1985) filed on September 22, 2014).
16.1	Letter re change in certifying accountant (incorporated by reference to Exhibit 16.16 to the Current Report on Form 8-K (File No. 001-36674) filed on December 4, 2014).
*21.1	Subsidiaries of the Registrant.
*23.1	Consent of BDO USA, LLP.
*23.2	Consent of UHY LLP.
*24.1	Powers of Attorney (included on the signature page to this Annual Report).
*31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document.
*101.SCH	XBRL Taxonomy Extension Schema Document.
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed or furnished herewith.

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# Management contract or compensatory plan arrangement required to be filed as an exhibit to this Annual Report pursuant to Item 15(b) of Form 10-K.

† Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been separately filed with the Securities and Exchange Commission.

Copies of Exhibits may be obtained upon written request of any Unitholder to Investor Relations, USD Partners LP, 811 Main Street, Suite 2800, Houston, Texas 77002.

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