USDP 10-Q Quarterly Report June 30, 2019

USD PARTNERS LP

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10-Q 1 usdp2019063010-q.htm 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-36674

USD PARTNERS LP

(Exact Name of Registrant as Specified in Its Charter)



Delaware		30-0831007
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

811 Main Street, Suite 2800

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

(Registrant’s Telephone Number, Including Area Code): (281) 291-0510

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	USDP	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES x NO ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ¨	Accelerated filer x
Non-accelerated filer ¨	Smaller reporting company x
	Emerging growth company x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. x

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 August 2, 2019 there were 24,411,280 common units, 2,092,709 subordinated units and 461,136 general partner units outstanding.

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income	1
	Consolidated Statements of Comprehensive Income	2
	Consolidated Statements of Cash Flows	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Partners’ Capital	5
	Notes to the Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	56
Item 4.	Controls and Procedures	56
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 6.	Exhibits	57
SIGNATURES		59

Unless the context otherwise requires, all references in this Quarterly Report on Form 10-Q, or this “Report,” to “USD Partners,” “USDP,” “the Partnership,” “we,” “us,” “our,” or like terms refer to USD Partners LP and its subsidiaries.

Unless the context otherwise requires, all references in this Report to (i) “our general partner” refer to USD Partners GP LLC, a Delaware limited liability company; (ii) “USD” refers to US Development Group, LLC, a Delaware limited liability company, and where the context requires, its subsidiaries; (iii) “USDG” and “our sponsor” refer to USD Group LLC, a Delaware limited liability company and currently the sole direct subsidiary of USD; (iv) “Energy Capital Partners” refers to Energy Capital Partners III, LP and its parallel and co-investment funds and related investment vehicles; and (v) “Goldman Sachs” refers to The Goldman Sachs Group, Inc. and its affiliates.

Cautionary Note Regarding Forward-Looking Statements

This 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 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, refineries or other related businesses; (4) the supply of, and demand for, terminalling services for crude oil and biofuels; (5) the price and availability of debt and equity financing; (6) actions by third parties, including customers, lenders and our sponsors; (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. For additional factors that may affect our results, see “ Item 1A. Risk Factors ” included elsewhere in this Report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 , which is available to the public over the Internet at the website of the U.S. Securities and Exchange Commission, or SEC, (www.sec.gov) and at our website (www.usdpartners.com).

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
	(unaudited; in thousands of US dollars, except per unit amounts)
Revenues
Terminalling services	$	19,730	$	22,511		$	39,728		$	44,516
Terminalling services — related party	5,525		5,003			11,163			9,699
Fleet leases — related party	983		983			1,967			1,967
Fleet services	51		81			108			425
Fleet services — related party	228		228			455			455
Freight and other reimbursables	298		769			701			2,244
Freight and other reimbursables — related party	—		2			61			4
Total revenues	26,815		29,577			54,183			59,310
Operating costs
Subcontracted rail services	3,699		3,311			7,264			6,373
Pipeline fees	4,902		5,118			9,963			10,842
Freight and other reimbursables	298		771			762			2,248
Operating and maintenance	2,510		2,498			5,721			4,854
Selling, general and administrative	2,722		2,455			5,199			5,449
Selling, general and administrative — related party	2,225		1,917			4,675			3,747
Depreciation and amortization	5,283		5,260			10,017			10,536
Total operating costs	21,639		21,330			43,601			44,049
Operating income	5,176		8,247			10,582			15,261
Interest expense	2,982		2,713			6,169			5,198
Loss (gain) associated with derivative instruments	1,074		(386		)	1,746			(1,410		)
Foreign currency transaction loss (gain)	20		117			202			(94		)
Other expense (income), net	21		1			(3		)	72
Income before income taxes	1,079		5,802			2,468			11,495
Provision for (benefit from) income taxes	128		(910		)	198			(1,817		)
Net income	$	951	$	6,712		$	2,270		$	13,312
Net income attributable to limited partner interests	$	774	$	6,498		$	1,929		$	12,897
Net income per common unit (basic and diluted)	$	0.03	$	0.25		$	0.07		$	0.49
Weighted average common units outstanding	24,410		21,914			23,739			21,259
Net income per subordinated unit (basic and diluted)	$	0.03	$	0.25		$	0.06		$	0.49
Weighted average subordinated units outstanding	2,093		4,185			2,671			4,764

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
	(unaudited; in thousands of US dollars)
Net income	$	951	$	6,712		$	2,270	$	13,312
Other comprehensive income (loss) — foreign currency translation	1,140		(998		)	2,555		(2,788		)
Comprehensive income	$	2,091	$	5,714		$	4,825	$	10,524

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six Months Ended June 30,
	2019			2018
	(unaudited; in thousands of US dollars)
Cash flows from operating activities:
Net income	$	2,270		$	13,312
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,017			10,536
Loss (gain) associated with derivative instruments	1,746			(1,410		)
Settlement of derivative contracts	1			(38		)
Unit based compensation expense	2,996			2,895
Deferred income taxes	(403		)	(2,538		)
Other	707			503
Changes in operating assets and liabilities:
Accounts receivable	(193		)	(2,614		)
Accounts receivable — related party	(671		)	(1,380		)
Prepaid expenses, inventory and other assets	(1,474		)	(2,460		)
Other assets — related party	40			40
Accounts payable and accrued expenses	2,052			865
Accounts payable and accrued expenses — related party	(43		)	2,113
Deferred revenue and other liabilities	2,929			(261		)
Deferred revenue — related party	(467		)	25
Net cash provided by operating activities	19,507			19,588
Cash flows from investing activities:
Additions of property and equipment	(2,677		)	(202		)
Proceeds from the sale of assets	—			236
Net cash provided by (used in) investing activities	(2,677		)	34
Cash flows from financing activities:
Distributions	(20,517		)	(19,593		)
Payments for deferred financing costs	(7		)	—
Vested phantom units used for payment of participant taxes	(1,821		)	(1,346		)
Proceeds from long-term debt	20,000			18,000
Repayments of long-term debt	(13,000		)	(15,000		)
Other financing activities	(13		)	—
Net cash used in financing activities	(15,358		)	(17,939		)
Effect of exchange rates on cash	605			(853		)
Net change in cash, cash equivalents and restricted cash	2,077			830
Cash, cash equivalents and restricted cash — beginning of period	12,383			13,788
Cash, cash equivalents and restricted cash — end of period	$	14,460		$	14,618

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	June 30, 2019			December 31, 2018
	(unaudited; in thousands of US dollars, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	7,168		$	6,439
Restricted cash	7,292			5,944
Accounts receivable, net	5,368			5,132
Accounts receivable — related party	1,317			624
Prepaid expenses	1,363			2,115
Inventory	2,239			241
Other current assets	385			393
Other current assets — related party	79			79
Total current assets	25,211			20,967
Property and equipment, net	148,178			145,308
Intangible assets, net	80,402			86,705
Goodwill	33,589			33,589
Operating lease right-of-use assets	14,342			—
Other non-current assets	188			631
Other non-current assets — related party	55			95
Total assets	$	301,965		$	287,295

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	7,867		$	3,464
Accounts payable and accrued expenses — related party	418			460
Deferred revenue	5,299			2,921
Deferred revenue — related party	1,470			1,885
Operating lease liabilities, current	5,317			—
Other current liabilities	3,325			2,804
Total current liabilities	23,696			11,534
Long-term debt, net	213,237			205,581
Deferred income tax liabilities, net	—			360
Operating lease liabilities, non-current	9,327			—
Other non-current liabilities	1,017			356
Total liabilities	247,277			217,831
Commitments and contingencies
Partners’ capital
Common units (24,410,226 and 21,916,024 outstanding at June 30, 2019 and December 31, 2018, respectively)	73,424			107,903
Class A units (38,750 outstanding at December 31, 2018)	—			1,018
Subordinated units (2,092,709 and 4,185,418 outstanding at June 30, 2019 and December 31, 2018, respectively)	(21,290		)	(39,723		)
General partner units (461,136 outstanding at June 30, 2019 and December 31, 2018)	3,008			3,275
Accumulated other comprehensive loss	(454		)	(3,009		)
Total partners’ capital	54,688			69,464
Total liabilities and partners’ capital	$	301,965		$	287,295

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Three Months Ended June 30,
	2019				2018
	Units	Amount			Units	Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at April 1,	24,408,073	$	80,539		21,914,224	$	116,125
Conversion of units	—	—			—	—
Common units issued for vested phantom units	2,153	—			—	—
Net income	—	713			—	5,448
Unit based compensation expense	—	1,444			—	1,338
Distributions	—	(9,272		)	—	(8,089		)
Ending balance at June 30,	24,410,226	73,424			21,914,224	114,822
Class A units
Beginning balance at April 1,	—	—			38,750	850
Conversion of units	—	—			—	—
Net income	—	—			—	10
Unit based compensation expense	—	—			—	50
Forfeited units	—	—			—	54
Distributions	—	—			—	(14		)
Ending balance at June 30,	—	—			38,750	950
Subordinated units
Beginning balance at April 1,	2,092,709	(20,555		)	4,185,418	(37,304		)
Conversion of units	—	—			—	—
Net income	—	61			—	1,040
Unit based compensation expense	—	—			—	11
Distributions	—	(796		)	—	(1,544		)
Ending balance at June 30,	2,092,709	(21,290		)	4,185,418	(37,797		)
General Partner units
Beginning balance at April 1,	461,136	3,147			461,136	138
Net income	—	177			—	214
Unit based compensation expense	—	—			—	—
Distributions	—	(316		)	—	(257		)
Ending balance at June 30,	461,136	3,008			461,136	95
Accumulated other comprehensive income (loss)
Beginning balance at April 1,		(1,594		)		44
Cumulative translation adjustment		1,140				(998		)
Ending balance at June 30,		(454		)		(954		)
Total partners’ capital at June 30,		$	54,688			$	77,116

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Six Months Ended June 30,
	2019					2018
	Units		Amount			Units		Amount
	(unaudited; in thousands of US dollars, except unit amounts)
Common units
Beginning balance at January 1,	21,916,024		$	107,903		19,537,971		$	136,645
Conversion of units	2,131,459		(19,631		)	2,131,459		(18,245		)
Common units issued for vested phantom units	362,743		(1,821		)	244,794		(1,346		)
Net income	—		1,767			—		10,543
Unit based compensation expense	—		2,733			—		2,440
Distributions	—		(17,527		)	—		(15,215		)
Ending balance at June 30,	24,410,226		73,424			21,914,224		114,822
Class A units
Beginning balance at January 1,	38,750		1,018			82,500		1,468
Conversion of units	(38,750	)	(1,018		)	(38,750	)	(674		)
Net income	—		—			—		24
Unit based compensation expense	—		14			—		101
Forfeited units	—		—			(5,000	)	73
Distributions	—		(14		)	—		(42		)
Ending balance at June 30,	—		—			38,750		950
Subordinated units
Beginning balance at January 1,	4,185,418		(39,723		)	6,278,127		(55,237		)
Conversion of units	(2,092,709	)	20,637			(2,092,709	)	18,919
Net income	—		162			—		2,330
Unit based compensation expense	—		2			—		26
Distributions	—		(2,368		)	—		(3,835		)
Ending balance at June 30,	2,092,709		(21,290		)	4,185,418		(37,797		)
General Partner units
Beginning balance at January 1,	461,136		3,275			461,136		180
Net income	—		341			—		415
Unit based compensation expense	—		—			—		1
Distributions	—		(608		)	—		(501		)
Ending balance at June 30,	461,136		3,008			461,136		95
Accumulated other comprehensive income (loss)
Beginning balance at January 1,			(3,009		)			1,834
Cumulative translation adjustment			2,555					(2,788		)
Ending balance at June 30,			(454		)			(954		)
Total partners’ capital at June 30,			$	54,688				$	77,116

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

USD PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

USD Partners LP and its consolidated subsidiaries, collectively referred to herein as we, us, our, the Partnership and USDP, is a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group, LLC, or USD, through its wholly-owned subsidiary, USD Group LLC, or USDG. We were formed to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitate the transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in onsite tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail. We do not generally take ownership of the products that we handle, nor do we receive any payments from our customers based on the value of such products. We may on occasion enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect such arrangements to be at fixed prices where we do not take commodity price exposure.

Basis of Presentation

Our accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and disclosures required by GAAP for complete consolidated financial statements. In the opinion of our management, they contain all adjustments, consisting only of normal recurring adjustments, which our management considers necessary to present fairly our financial position as of June 30, 2019 , our results of operations for the three and six months ended June 30, 2019 and 2018 , and our cash flows for the six months ended June 30, 2019 and 2018 . We derived our consolidated balance sheet as of December 31, 2018 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 . Our results of operations for three and six months ended June 30, 2019 and 2018 should not be taken as indicative of the results to be expected for the full year due to fluctuations in the supply of and demand for crude oil and biofuels, timing and completion of acquisitions, if any, changes in the fair market value of our derivative instruments and the impact of fluctuations in foreign currency exchange rates. These unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and accompanying notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 .

Foreign Currency Translation

We conduct a substantial portion of our operations in Canada, which we account for in the local currency, the Canadian dollar. We translate most Canadian dollar denominated balance sheet accounts into our reporting currency, the U.S. dollar, at the end of period exchange rate, while most income statement accounts are translated into our reporting currency based on the average exchange rate for each monthly period. Fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar can create variability in the amounts we translate and report in U.S. dollars.

Within these consolidated financial statements, we denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.

US Development Group, LLC

USD and its affiliates are engaged in designing, developing, owning and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USD is the indirect owner of our general partner through its direct ownership of USDG and is currently owned by Energy Capital Partners, Goldman Sachs and certain of USD’s management team members.

Comparative Amounts

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

We adopted the provisions of ASC 842 Leases on January 1, 2019. We elected to implement the provisions of the new standard to our existing leases by recognizing and measuring lease assets and liabilities on our balance sheet as of January 1, 2019, as well as any cumulative-effect adjustment to the opening balance of Partners' Capital. Refer to Note 2. Recent Accounting Pronouncements and Note 8. Leases for further discussion.

2. RECENT ACCOUNTING PROUNOUNCEMENTS

Recently Adopted Accounting Pronouncements

Accounting for Nonemployee Unit based Compensation (ASU 2018-07)

In June 2018, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2018-07, or ASU 2018-07, which amends the Accounting Standards Codification, or ASC, Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The provisions of this standard specify that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be used or consumed in a grantor’s own operations by issuing share-based payment awards. We adopted the provisions of ASU 2018-07 prospectively on January 1, 2019, which affected the method we used to value the phantom units we granted to our directors and consultants domiciled in the United States. In periods prior to our adoption of ASU 2018-07, we were required to revalue the outstanding phantom units granted to these individuals each reporting period. Pursuant to the requirements of ASU 2018-07 and under the provisions of ASC Topic 718, these phantom units are now valued at the grant date fair value, consistent with the method we use to value phantom units granted to employees that are domiciled in the United States.

Leases (ASC 842)

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, or ASU 2016-02, which created ASC Topic 842 Leases, to require balance sheet recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The standard also expanded the disclosure requirements for lessors with respect to their leasing activities. In July 2018, the FASB issued ASU 2018-11, to provide another transition method in addition to the existing transition method, allowing entities to initially apply the new standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, the FASB has issued other Accounting Standards Updates to clarify application of the guidance in the original standard and to provide practical expedients for applying the standard, all of which were effective upon adoption. The pronouncement was effective for years beginning after December 15, 2018, and early adoption is permitted.

We adopted the provisions of ASC 842 on January 1, 2019. This standard requires us to recognize right-of-use assets and lease liabilities on our consolidated balance sheet for identified property that is subject to operating lease agreements for which we are considered a lessee. We elected to adopt this standard by applying the additional transition method set forth in ASU 2018-11, whereby we implement the provisions of the new standard to our existing leases by recognizing and measuring lease assets and liabilities on our balance sheet as of January 1, 2019, as well as a cumulative-effect adjustment to the opening balances of Partners’ Capital. Consequently, our reporting of leases for the prior year continues to be provided in accordance with ASC Topic 840, which was effective during that period. We elected the package of practical expedients permitted under the transition guidance within ASC 842, which, among other things, allowed us to carry forward our historical lease classification without the need to re-evaluate such classification pursuant to the provisions of ASC 842.

We determine the classification of our leases as operating, financing or sales-type leases based on the criteria set forth in ASC 842 that considers whether a lease is economically similar to the purchase of a nonfinancial asset. We

have adopted as our accounting policy the definition of “substantially all” of the fair value of the underlying asset to mean 90% or greater and a “major part” of the remaining economic life to mean 75% or greater in performing our classification assessment. We exclude variable lease payments that are based on performance or use from our lease classification determination. We include the exercise price of a purchase option when reasonable certainty exists that we will exercise the option. We also include termination penalties unless it is reasonably certain that we will not exercise any option to terminate the lease, and therefore will not incur the penalty. Lastly, we also include any residual value guarantees that we provided to lessors in our classification determination.

Our adoption of ASC 842 required us to recognize lease assets and lease liabilities for all leases where we are the lessee and present them on our balance sheet, which did not affect our consolidated statements of income, consolidated statement of cash flows or consolidated statements of partners' capital. Upon adoption we recognized a right-of-use lease asset and corresponding liability of $17.3 million on our consolidated balance sheet. Additionally, our adoption of ASC 842 did not affect our accounting for leases where we are the lessor.

Lessee Accounting

We lease assets from third parties for use in our operations, which primarily include railcars, buildings, storage tanks, equipment, offices, railroad track and land. The general terms of our lease agreements require monthly payments in advance, in arrears or upon receipt, some of which include variable payments attributable to index-based rate escalations and freight associated with railcar returns. A majority of our leases do not include renewal options, or rights to early termination of the lease agreements. Additionally, our leases do not include residual value guarantees, nor do they impose any significant covenants or restrictions on us. As discussed below under Lessor Accounting, we effectively sublease all of our leased railcars to customers under terms similar to the terms of our lease agreements with the railcar manufacturing and finance companies from whom we lease the railcars. We also lease a storage tank from a third party provider of crude oil storage that we sublease to a customer of our Stroud terminal.

We have elected as an accounting policy not to apply the recognition requirements of ASC 842 to short-term leases for all classes of assets underlying our leases. As a result, we recognize the lease payments we make as expense in our consolidated statements of income over the lease term, regardless of the underlying class of asset being leased. We define a short-term lease as a lease that at the commencement date has a term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise.

We deem a contract to be a lease when the terms of the agreement indicate we have the right to control the use of an identified asset for a period of time in exchange for consideration. We establish our right to control the use of an identified asset when the contract terms set forth our right to obtain substantially all of the economic benefits from use of the identified asset, or to direct its use throughout the contract period. We consider substantially all of the economic benefits to mean 90% or more of the utility of the identified asset.

We have elected to apply the portfolio approach to account for our railcar leases due to our expectation that this method would not significantly differ from an individual lease approach. Additionally, we have elected to use the practical expedient that allows us not to separate amounts of contract consideration between lease and non-lease components. Non-lease components of our agreements include maintenance of property, common area costs such as cleaning and landscape services and reimbursement of the suppliers’ insurance, taxes or administrative costs.

We determine the discount rate for our leases by estimating a borrowing rate we would pay on a collateralized basis over the term of the underlying lease, based on our creditworthiness and the interest rate environment at the time we enter into the lease. We establish our credit quality by performing a synthetic credit analysis based on operational, liquidity and solvency metrics, which are weighted to produce an estimated rating. We then develop an interest rate curve for various periods of time by applying an adjustment factor to the risk free rates as established from yields on U.S. Treasury securities. We utilize this interest rate curve to establish an approximate discount rate based upon the term of the underlying lease.

We determine our right-of-use assets based on the initial measurement amount of the lease liability, as discussed below, increased by any prepayments that we make to the lessor at or before the lease commencement date and any initial direct costs we may incur, reduced by any incentive amounts we may receive.

We measure our lease liabilities based upon the discounted present value of the payment amounts we expect to make over the noncancellable terms of the underlying leases. We exclude variable lease payments that are based on performance or use in our measurement of the right of use assets and liabilities. We include in our measurement of the right of use assets and lease liabilities the exercise price of purchase options when reasonable certainty exists that we will exercise the option and any termination penalties when reasonable certainty exists that we will exercise an option to terminate the lease. We also include any residual value guarantees provided to lessors to the extent that we consider the likelihood we will have to pay the lessor at the end of the lease term for a deficiency to be probable.

Over the lease term, we amortize the right-of-use asset and record interest expense on the lease liability recorded at commencement of the lease. Our income statement recognition of the expense is dependent on whether the lease is classified as an operating, direct financing, or sales-type lease. We recognize amortization expense and interest expense associated with operating leases as a single item of expense in our consolidated statements of income. We recognize amortization expense and interest expense associated with any direct financing and sales-type leases as separate items of expense within our consolidated statements of income.

We present all leases, where we are the lessee, on our balance sheet subject to the practical expedients we have elected and capitalization limitations we have established.

Lessor Accounting

We effectively lease railcars and storage tanks to customers of our terminalling facilities to meet their logistical needs for the movement of crude oil to refineries and market centers. The general terms of our lease agreements require monthly payments, some of which include variable payments attributable to index-based rate escalations and freight associated with railcar returns. Under the master service agreements for the railcars we lease, we also charge a fee for the various freight monitoring, scheduling, maintenance and related services we provide to customers that lease railcars from us, representing a non-lease component that we account for separately. Our storage tank leases contain standard renewal options for periods up to 12 months following the end of the initial lease term. Additionally, our storage tank leases include charges for blending and mixing services as well as pump over charges, representing non lease components that we account for separately. Our railcar master fleet services agreements and storage tank leases do not generally include rights to early termination of the agreements, nor do they include residual value guarantees. None of the customers on our railcar master fleet services agreements and storage tank leases have options to purchase the underlying assets. As discussed above under Lessee Accounting, we effectively sublease all of our leased railcars to customers under terms similar to the terms of our lease agreements with the railcar manufacturing and finance companies from whom we lease the railcars. We also lease a storage tank from a third party provider of crude oil storage that we sublease to a customer of our Stroud terminal.

We deem a contract to be a lease when the terms of the agreement indicate we have transferred to another party the right to control the use of an identified asset for a period of time in exchange for consideration. We determine that we have transferred the right to control the use of an identified asset when the contract terms set forth the rights of another party to obtain substantially all of the economic benefits from use of the identified asset, or to direct its use throughout the contract period. We consider substantially all of the economic benefits to mean 90% or more of the utility of the identified asset during the contract term.

We allocate consideration in a contract between lease and non-lease components based upon the rates and terms that are specified in our agreements. We recognize revenue from fees we charge for freight services related to railcars and from fees we charge for blending, mixing and pump over charges related to our storage services pursuant to the requirements of ASC 606 as set forth in our Revenue Policy.

We continue to depreciate property that we own and lease to third party customers in accordance with our standard depreciation policies. We record lease income typically on a straight-line basis over the lease term.

Refer to Note 8. Leases for further discussion.

Recent Accounting Pronouncements Not Yet Adopted

Intangibles - Goodwill and Other

In January 2017, the FASB issued Accounting Standards Update No. 2017-04, or ASU 2017-04, which amends ASC Topic 350 to modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. Pursuant to the provisions of ASU 2017-04, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Rather, an entity will recognize an impairment loss for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. However, the loss recognized cannot exceed the total amount of goodwill allocated to that reporting unit.

The pronouncement is effective for fiscal years beginning after December 15, 2019, or for any interim impairment testing within those fiscal years and is required to be applied prospectively, with early adoption permitted. We do not expect to early adopt the provisions of this standard. Any impairment assessment we perform subsequent to our adoption of the standard could produce an impairment of goodwill in a different amount than would result under current guidance to the extent the carrying amount of a reporting unit exceeds its fair value.

3. NET INCOME PER LIMITED 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 and any net income in excess of distributions to our limited partners, our general partner and the holder of the incentive distribution rights, or IDRs, according to the distribution formula for available cash as set forth in our partnership agreement. We allocate any distributions in excess of earnings for the period to our limited partners and general partner based on their respective proportionate ownership interests in us, as set forth in our partnership agreement after taking into account distributions to be paid with respect to the IDRs. The formula for distributing available cash as set forth in our partnership agreement is as follows:



Distribution Targets	Portion of Quarterly Distribution Per Unit	Percentage Distributed to Limited Partners	Percentage Distributed to General Partner (including IDRs) ⁽¹⁾
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	> $0.359375 to $0.431250	75%	25%
Thereafter	Amounts above $0.431250	50%	50%


⁽¹⁾	Assumes our general partner maintains a 2% general partner interest in us.

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



	For the Three Months Ended June 30, 2019
	Common Units			Subordinated Units			Class A Units ⁽⁷⁾		General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	713		$	61		$	—	$	177		$	951
Less: Distributable earnings ⁽²⁾	9,336			801			—		338			10,475
Distributions in excess of earnings	$	(8,623	)	$	(740	)	$	—	$	(161	)	$	(9,524	)
Weighted average units outstanding ⁽³⁾	24,410			2,093			—		461			26,964
Distributable earnings per unit ⁽⁴⁾	$	0.38		$	0.38		$	—
Overdistributed earnings per unit ⁽⁵⁾	(0.35		)	(0.35		)	—
Net income per limited partner unit (basic and diluted) ⁽⁶⁾	$	0.03		$	0.03		$	—


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $161 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions payable for the period based upon the quarterly distribution amount of $0.365 per unit, or $1.46 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $471 thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.


⁽³⁾	Represents the weighted average units outstanding for the period.


⁽⁴⁾	Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.


⁽⁵⁾	Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,292,474 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.


⁽⁷⁾	In February 2019 , pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and were converted into Common units. Refer to Note 18. Partners Capital for more information.



	For the Three Months Ended June 30, 2018
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	5,448		$	1,040		$	10		$	214		$	6,712
Less: Distributable earnings ⁽²⁾	8,143			1,555			14			268			9,980
Distributions in excess of earnings	$	(2,695	)	$	(515	)	$	(4	)	$	(54	)	$	(3,268	)
Weighted average units outstanding ⁽³⁾	21,914			4,185			39			461			26,599
Distributable earnings per unit ⁽⁴⁾	$	0.37		$	0.37		$	0.36
Overdistributed earnings per unit ⁽⁵⁾	(0.12		)	(0.12		)	(0.10		)
Net income per limited partner unit (basic and diluted) ⁽⁶⁾	$	0.25		$	0.25		$	0.26


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $97 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution amount of $0.355 per unit, or $1.42 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $440 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.


⁽³⁾	Represents the weighted average units outstanding for the period.


⁽⁴⁾	Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.


⁽⁵⁾	Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,240,988 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.



	For the Six Months Ended June 30, 2019
	Common Units			Subordinated Units			Class A Units ⁽⁷⁾		General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	1,767		$	162		$	—	$	341		$	2,270
Less: Distributable earnings ⁽²⁾	18,609			1,595			—		654			20,858
Distributions in excess of earnings	$	(16,842	)	$	(1,433	)	$	—	$	(313	)	$	(18,588	)
Weighted average units outstanding ⁽³⁾	23,739			2,671			11		461			26,882
Distributable earnings per unit ⁽⁴⁾	$	0.78		$	0.60		$	—
Overdistributed earnings per unit ⁽⁵⁾	(0.71		)	(0.54		)	—
Net income per limited partner unit (basic and diluted) ⁽⁶⁾	$	0.07		$	0.06		$	—


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $302 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the per unit distributions paid of $0.3625 per unit for the three months ended March 31, 2019 and $0.365 per unit distributable for the three months ended June 30, 2019, representing a year-to-date distribution amount of $0.7275 per unit. Amounts presented for each class of units include a proportionate amount of the $469 thousand distributed and $471 thousand distributable to holders of the Equity classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners LP 2014 Amended and Restated Long-Term Incentive Plan.


⁽³⁾	Represents the weighted average units outstanding for the period.


⁽⁴⁾	Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.


⁽⁵⁾	Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,292,474 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.


⁽⁷⁾	In February 2019 , pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and were converted into Common units. Refer to Note 18. Partners Capital for more information.



	For the Six Months Ended June 30, 2018
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	10,543		$	2,330		$	24		$	415		$	13,312
Less: Distributable earnings ⁽²⁾	16,232			3,099			28			525			19,884
Distributions in excess of earnings	$	(5,689	)	$	(769	)	$	(4	)	$	(110	)	$	(6,572	)
Weighted average units outstanding ⁽³⁾	21,259			4,764			50			461			26,534
Distributable earnings per unit ⁽⁴⁾	$	0.76		$	0.65		$	0.56
Overdistributed earnings per unit ⁽⁵⁾	(0.27		)	(0.16		)	(0.08		)
Net income per limited partner unit (basic and diluted) ⁽⁶⁾	$	0.49		$	0.49		$	0.48


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $184 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution amount of $0.3525 per unit for the three months ended March 31, 2018 and $0.355 per unit for the three months ended June 30, 2018, representing a year-to-date distribution amount of $0.7075 per unit. Amounts presented for each class of units include a proportionate amount of the $881 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners Amended and Restated LP 2014 Long-Term Incentive Plan.


⁽³⁾	Represents the weighted average units outstanding for the period.


⁽⁴⁾	Represents the total distributable earnings divided by the weighted average number of units outstanding for the period.


⁽⁵⁾	Represents the distributions in excess of earnings divided by the weighted average number of units outstanding for the period.


⁽⁶⁾	Our computation of net income per limited partner unit excludes the effects of 1,240,988 equity-classified phantom unit awards outstanding as they were anti-dilutive for the period presented.

4. REVENUES

Disaggregated Revenues

We manage our business in two reportable segments: Terminalling services and Fleet services. Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. As such, we have concluded that disaggregating revenue by reporting segments appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Refer to Note 15. Segment Reporting for our disaggregated revenues by segment. Additionally, the below tables summarize the geographic data for our revenues:



	Three Months Ended June 30, 2019
	U.S.		Canada		Total
	(in thousands)
Third party	$	8,722	$	11,357	$	20,079
Related party	$	2,208	$	4,528	$	6,736



	Three Months Ended June 30, 2018
	U.S.		Canada		Total
	(in thousands)
Third party	$	11,471	$	11,890	$	23,361
Related party	$	1,603	$	4,613	$	6,216



	Six Months Ended June 30, 2019
	U.S.		Canada		Total
	(in thousands)
Third party	$	17,442	$	23,095	$	40,537
Related party	$	4,582	$	9,064	$	13,646



	Six Months Ended June 30, 2018
	U.S.		Canada		Total
	(in thousands)
Third party	$	23,168	$	24,017	$	47,185
Related party	$	2,814	$	9,311	$	12,125

Remaining Performance Obligations

The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of June 30, 2019 are as follows for the periods indicated:



	For the six months ending December 31, 2019		2020		2021		2022		Thereafter		Total
	(in thousands)
Terminalling Services ^{(1) (2)}	$	43,768	$	65,548	$	50,894	$	42,828	$	17,331	$	220,369
Fleet Services	742		1,030		1,016		1,267		41		4,096
Total	$	44,510	$	66,578	$	51,910	$	44,095	$	17,372	$	224,465

⁽¹⁾ The majority of our terminalling services agreements are denominated in Canadian dollars. We have converted the remaining performance obligations provided herein using the year-to-date average exchange rate of 0.7499 U.S. dollars per one Canadian dollar at June 30, 2019 .

⁽²⁾ Includes fixed monthly minimum commitment fees per contracts and excludes constrained variable consideration for rate-escalations associated with an index, such as the consumer price index, as well as any incremental revenue associated with volume activity above the minimum volumes set forth within the contracts.

We have applied the practical expedient that allows us to exclude disclosure of performance obligations that are part of a contract that has an expected duration of one year or less . In addition, we have also applied the practical expedient that allows us not to disclose the amount of transaction price allocated to the remaining performance obligations for all reporting periods presented prior to our adoption of ASC 606.

Contract Assets

Our contract assets represent cumulative revenue that has been recognized in advance of billing the customer due to tiered billing provisions. In such arrangements, revenue is recognized using a blended rate based on the billing tiers of the agreement, as the services are consistently provided throughout the duration of the contractual arrangement. We have included contract assets of $342 thousand and $68 thousand as of June 30, 2019 and December 31, 2018 , respectively, in “ Other current assets ” and $171 thousand as of December 31, 2018 , in “ Other non - current assets ” on our consolidated balance sheets.

Contract Liabilities

Our contract liabilities consist of amounts collected in advance from customers associated with their terminalling and fleet services agreements and deferred revenues associated with make-up rights, which will be recognized as revenue when earned pursuant to the terms of our contractual arrangements. We currently recognize substantially all of the amounts we receive for minimum commitment fees as revenue when collected, since breakage associated with these make-up rights options approximates 100% based on our experience and expectations around usage of these options. We deferred $0.3 million in revenues at June 30, 2019 for estimated breakage associated with the make-up right options we granted to our customers, which we included in “ Deferred revenue ” on our consolidated balance sheets.

We have included contract liabilities with third-party customers of $5.3 million and $2.9 million as of June 30, 2019 and December 31, 2018 , respectively, in “ Deferred revenue. ” We have included contract liabilities with related party customers of $1.1 million and $1.5 million as of June 30, 2019 and December 31, 2018 , respectively, in “ Deferred revenue — related party ” on our consolidated balance sheets.

The following table presents the changes associated with the balance of our contract liabilities for the six months ended June 30, 2019 :



	December 31, 2018		Cash Additions for Customer Prepayments		Revenue Recognized			June 30, 2019
	(in thousands)
Customer prepayments	$	2,921	$	5,299	$	(2,921	)	$	5,299
Customer prepayments — related party ⁽¹⁾	$	1,475	$	1,060	$	(1,475	)	$	1,060


⁽¹⁾	Includes contract liabilities associated with customer prepayments from related parties. Refer to Note 13. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties.

Deferred Revenue — Fleet Leases

Our deferred revenue also includes advance payments from customers of our Fleet services business, which will be recognized as Fleet leases revenue when earned pursuant to the terms of our contractual arrangements. We have likewise prepaid the rent on railcar leases that are associated with the deferred revenues of our fleet services business, which we will recognize as expense concurrently with our recognition of the associated revenue. We have included $0.4 million at June 30, 2019 and December 31, 2018 , in “ Deferred revenue — related party ” on our consolidated balance sheets associated with customer prepayments for our fleet lease agreements.

5. 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 a facilities connection agreement among us and Gibson Energy Inc., or Gibson, that we entered into during 2014 in connection with the development of our Hardisty terminal. The collaborative arrangement is further discussed in Note 11. Collaborative Arrangement .

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets to the amounts shown in our consolidated statements of cash flows for the specified periods:



	June 30,
	2019		2018
	(in thousands)
Cash and cash equivalents	$	7,168	$	8,926
Restricted Cash	7,292		5,692
Total cash, cash equivalents and restricted cash	$	14,460	$	14,618

6. INVENTORY

Our inventory of $2.2 million and $0.2 million at June 30, 2019 and December 31, 2018 , respectively, is comprised of crude oil we acquired as a result of buy-sell arrangements that we enter into, whereby we take title to commodities on a temporary basis. We record our inventory at cost, representing the amount we pay to purchase the crude oil, and account for it on a first-in, first-out, or FIFO, basis. The purchase price we pay for the crude oil is set forth in our buy-sell agreements and is determined from an indexed market price. The market price at which we ultimately sell the crude oil is determined based on the same indexed market price as the crude oil purchase, plus an agreed-upon rate differential. The difference between the purchase price and the selling price establishes a fixed amount we receive, on a per barrel basis, when the inventory is sold pursuant to the terms of our buy-sell arrangements, eliminating any commodity price exposure to us. Based on the terms of our buy-sell arrangements, the selling price will always be greater than the cost of our inventory. The resulting income we receive represents a fee for the terminalling services we provide our customers, which we record net in “Terminalling services” on our consolidated statement of income.

7. PROPERTY AND EQUIPMENT

Our property and equipment is comprised of the following as of the dates indicated:



	June 30, 2019			December 31, 2018			Estimated Depreciable Lives (Years)
	(in thousands)						Estimated Depreciable Lives (Years)
Land	$	10,120		$	10,004		N/A
Trackage and facilities	125,636			123,080			10-30
Pipeline	16,336			16,336			20-25
Equipment	16,725			16,455			3-20
Furniture	66			64			5-10
Total property and equipment	168,883			165,939
Accumulated depreciation	(34,447		)	(29,479		)
Construction in progress ⁽¹⁾	13,742			8,848
Property and equipment, net	$	148,178		$	145,308

⁽¹⁾

The amounts classified as “Construction in progress” are excluded from amounts being depreciated. These amounts represent property that is not yet ready to be placed into productive service as of the respective consolidated balance sheet date. We had $131 thousand and $269 thousand of capitalized interest costs for the three and six months ended June 30, 2019 , respectively, and none for the same periods in 2018 .

Depreciation expense associated with Property and equipment totaled $2.1 million for the three months ended June 30, 2019 and 2018 , and $3.7 million and $4.2 million for the six months ended June 30, 2019 and 2018 , respectively.

Our depreciation expense for the six months ended June 30, 2019 reflects a reduction of $0.6 million to our asset retirement obligations, or ARO, due to refinement of our estimates. The ARO is associated with restoration of the property at our San Antonio facility. The ending balance of our ARO at June 30, 2019 is $0.2 million and is recorded as “ Other current liabilities ” on our consolidated balance sheets.

8. LEASES

We have noncancellable operating leases for railcars, buildings, storage tanks, offices, railroad tracks, and land.



	For the Six Months Ended June 30, 2019
Weighted-average discount rate	6.3	%
Weighted average remaining lease term	3.2 years

Our total lease cost consisted of the following items for the dates indicated:



		For the Three Months Ended June 30, 2019			For the Six Months Ended June 30, 2019
	(in thousands)
Operating lease cost		$	1,484		$	2,968
Short term lease cost		52			99
Sublease income		(1,337		)	(2,670		)
Total		$	199		$	397

The maturity analysis below presents the undiscounted cash payments we expect to make each period for property that we lease from others under noncancellable operating leases as of June 30, 2019 (in thousands):



2019	$	3,039
2020	5,269
2021	4,074
2022	3,787
2023	20
Total lease payments	$	16,189
Less: imputed interest	(1,545		)
Present value of lease liabilities	$	14,644

We serve as an intermediary to assist our customers with obtaining railcars. In connection with our leasing of railcars from third parties, we simultaneously enter into lease agreements with our customers for noncancellable terms that are designed to recover our costs associated with leasing the railcars plus a fee for providing this service. In addition to these leases we also have lease income from storage tanks.



	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
	(in thousands, except weighted average term)
Lease income	$	2,314	$	4,609
Weighted average remaining lease term			3.2 years

The maturity analysis below presents the undiscounted future minimum lease payments we expect to receive from customers each period for property they lease from us under noncancellable operating leases as of June 30, 2019 (in thousands):



2019	$	3,992
2020	6,895
2021	5,752
2022	4,459
Total	$	21,098

Refer to Note 2. Recent Accounting Pronouncements for additional discussion of our lease policies.

9. INTANGIBLE ASSETS

The composition, gross carrying amount and accumulated amortization of our identifiable intangible assets are as follows as of the dates indicated:



	June 30, 2019			December 31, 2018
	(in thousands)
Carrying amount:
Customer service agreements	$	125,960		$	125,960
Other	106			106
Total carrying amount	126,066			126,066
Accumulated amortization:
Customer service agreements	(45,626		)	(39,328		)
Other	(38		)	(33		)
Total accumulated amortization	(45,664		)	(39,361		)
Total intangible assets, net	$	80,402		$	86,705

Amortization expense associated with intangible assets totaled $3.2 million for each of the three months ended June 30, 2019 and 2018 and $6.3 million for each of the six months ended June 30, 2019 and 2018 .

10. DEBT

In November 2018, we amended and restated our senior secured credit agreement, which we originally established at the time of our initial public offering in October 2014. We refer to the amended and restated senior secured credit agreement executed in November 2018 as the Credit Agreement and the original senior secured credit agreement as the Previous Credit Agreement. Our Credit Agreement is a $385 million revolving credit facility (subject to limits set forth therein) with Citibank, N.A., as administrative agent, and a syndicate of lenders. Our Credit Agreement amends and restates in its entirety our Previous Credit Agreement.

Our Credit Agreement is a four year committed facility that initially matures on November 2, 2022. Our Credit Agreement provides us with the ability to request two one -year maturity date extensions, subject to the satisfaction of certain conditions, and allows us the option to increase the maximum amount of credit available up to a total facility size of $500 million , subject to receiving increased commitments from lenders and satisfaction of certain conditions.

Our Credit Agreement and any issuances of letters of credit are available for working capital, capital expenditures, general partnership purposes and continue the indebtedness outstanding under the Previous Credit Agreement. The Credit Agreement includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the Credit Agreement are guaranteed by our restricted subsidiaries (as such term is defined therein) and are secured by a first priority lien on our assets and those of our restricted subsidiaries, other than certain excluded assets.

Our long-term debt balances included the following components as of the specified dates:



	June 30, 2019			December 31, 2018
	(in thousands)
Revolving Credit Facility	$	216,000		$	209,000
Less: Deferred financing costs, net	(2,763		)	(3,419		)
Total long-term debt, net	$	213,237		$	205,581

We determined the capacity available to us under the terms of our Credit Agreement was as follows as of the specified dates:



	June 30, 2019		December 31, 2018
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	385.0	$	385.0
Less: Revolving Credit Facility amounts outstanding	216.0		209.0
Letters of credit outstanding	0.6		0.6
Available under Credit Agreement ⁽¹⁾	$	168.4	$	175.4


⁽¹⁾	Pursuant to the terms of our Credit Agreement, our borrowing capacity, currently, is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to approximately $34 million of availability at June 30, 2019 .

The average interest rate on our outstanding indebtedness was 4.92% and 4.86% at June 30, 2019 and December 31, 2018 , respectively, without consideration to the effect of our derivative contracts. In addition to the interest we incur on our outstanding indebtedness, we pay commitment fees of 0.50% on unused commitments, which rate will vary based on our consolidated net leverage ratio, as defined in our Credit Agreement. At June 30, 2019 , we were in compliance with the covenants set forth in our Credit Agreement.

Interest expense associated with our outstanding indebtedness was as follows for the specified periods:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
	(in thousands)
Interest expense on the Credit Agreement	$	2,906		$	2,498	$	5,781		$	4,768
Capitalized interest on construction in progress	(131		)	—		(269		)	—
Amortization of deferred financing costs	207			215		657			430
Total interest expense	$	2,982		$	2,713	$	6,169		$	5,198

11. COLLABORATIVE ARRANGEMENT

We entered into a facilities connection agreement in 2014 with Gibson under which Gibson developed, constructed and operates a pipeline and related facilities connected to our Hardisty terminal. Gibson’s storage terminal is the exclusive means by which our Hardisty terminal receives crude oil. Subject to certain limited exceptions regarding manifest train facilities, our Hardisty terminal is the exclusive means by which crude oil from Gibson’s Hardisty storage terminal may be transported by rail. We remit pipeline fees to Gibson for the transportation of crude oil to our Hardisty terminal based on a predetermined formula. Pursuant to our arrangement with Gibson, we incurred pipeline fees of $4.9 million and $5.1 million for the three months ended June 30, 2019 and 2018 , respectively, and $10.0 million and $10.8 million for the six months ended June 30, 2019 and 2018 , respectively, which are presented as “Pipeline fees” in our consolidated statements of income.

12. NONCONSOLIDATED 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, as well as customer fleet service payments related to these operating leases, with unconsolidated entities in which we have variable interests. These variable interest entities, or VIEs, include LRT Logistics Funding LLC, USD Fleet Funding LLC, USD Fleet Funding Canada Inc., and USD Logistics Funding Canada Inc. We treat these entities as variable interests under the applicable accounting guidance due to their having an insufficient amount of equity invested at risk to finance their activities without additional subordinated financial support. We are not the primary beneficiary of the VIEs, as we do not have the power to direct the activities that most significantly affect the economic performance of the VIEs, nor do we have the power to remove the managing member under the terms of the VIEs’ limited liability company agreements. Accordingly, we do not consolidate the results of the VIEs in our consolidated financial statements.

The following table summarizes the total assets and liabilities between us and the VIEs as reflected in our consolidated balance sheets at June 30, 2019 and December 31, 2018 , as well as our maximum exposure to losses from entities in which we have a variable interest, but are not the primary beneficiary. Generally, our maximum exposure to losses is limited to amounts receivable for services we provided, reduced by any deferred revenue.



	June 30, 2019
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	11	$	—	$	1
Deferred revenue	—		10		—
	$	11	$	10	$	1



	December 31, 2018
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	17	$	—	$	7
Deferred revenue	—		10		—
	$	17	$	10	$	7

We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,483 railcars to the VIEs, but we have retained certain rights and obligations with respect to the servicing of these railcars.

During the quarter ended June 30, 2019 , we provided no explicit or implicit financial or other support to these VIEs that were not previously contractually required.

13. TRANSACTIONS WITH RELATED PARTIES

Nature of Relationship with Related Parties

USD is engaged in designing, developing, owning and managing large-scale multi-modal logistics centers and other energy-related infrastructure across North America. USD is also 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 at June 30, 2019 , owns 9,464,381 of our common units and all 2,092,709 of our subordinated units representing a combined 42.9% limited partner interest in us. As of June 30, 2019, a value of up to $10.0 million of these common units were pledged as collateral under USDG’s letter of credit facility. 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, currently owns all 461,136 of our general partner units representing a 1.7% general partner interest in us, as well as all of our incentive distribution rights. Pursuant to our partnership agreement, our general partner is responsible for our overall governance and operations.

USD Marketing LLC, or USDM, is a wholly-owned subsidiary of USDG organized to promote contracting for services provided by our terminals and to facilitate the marketing of customer products.

Omnibus Agreement

We are party to an omnibus agreement with USD, USDG and certain of their subsidiaries, including our general partner, pursuant to which we obtain and make payments for specified services provided to us and for out-of-pocket costs incurred on our behalf. We pay USDG, in equal monthly installments, the annual amount USDG estimates will be payable by us during the 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, which affects the cost of providing the general and administrative services. We also reimburse USDG for any out-of-pocket costs and expenses incurred on our behalf in providing general and administrative services to us. This reimbursement is in addition to the amounts we pay to reimburse our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing our business and operations, as required by our partnership agreement.

The total amounts charged to us under the omnibus agreement for the three months ended June 30, 2019 and 2018 were $2.2 million and $1.9 million , respectively, and for the six months ended June 30, 2019 and 2018 were $4.7 million and $3.7 million , respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At June 30, 2019 and December 31, 2018 , we had balances payable

related to these costs of $0.3 million and $0.4 million , respectively, recorded as “Accounts payable and accrued expenses — related party” in our consolidated balance sheets.

Marketing Services Agreement

In connection with our purchase of the Stroud terminal, we entered into a Marketing Services Agreement with USDM effective as of May 31, 2017, whereby we granted USDM the right to market the capacity at the Stroud terminal in excess of the original capacity of our initial customer in exchange for a nominal per barrel fee. USDM is obligated to fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional throughput. Upon expiration of our contract with the initial Stroud customer in June 2020, the same marketing rights will apply to all throughput at the Stroud terminal in excess of the throughput necessary for the Stroud terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud customer during the 12 months prior to expiration. We also granted USDG the right to develop other projects at the Stroud terminal in exchange for the payment to us of market-based compensation for the use of our property for such development projects. Any such development projects would be wholly-owned by USDG and would be subject to our existing right of first offer with respect to midstream projects developed by USDG. Payments made under the Marketing Services Agreement during the periods presented in this report are discussed below under the heading “ Related Party Revenue and Deferred Revenue. ”

Related Party Revenue and Deferred Revenue

We have agreements to provide terminalling and fleet services for USDM with respect to our Hardisty terminal and terminalling services with respect to our Stroud terminal, which also include reimbursement to us for certain out-of-pocket expenses we incur.

In connection with our acquisition of the Stroud terminal, USDM assumed the rights and obligations for additional terminalling capacity at our Hardisty terminal from another customer, effective as of June 1, 2017, to facilitate the origination of crude oil barrels by the Stroud customer from our Hardisty terminal for delivery to the Stroud terminal. As a result of the assumption of these rights and obligations by USDM, and in order to accommodate the needs of the Stroud customer, the contracted term for the capacity held by USDM was extended to June 30, 2020. USDM controls approximately 25% of the available monthly capacity of the Hardisty terminal at June 30, 2019 . The terms and conditions of these agreements are similar to the terms and conditions of agreements we have with other parties at the Hardisty terminal that are not related to us.

We also entered into a Marketing Services Agreement with USDM effective as of May 31, 2017, as discussed above, in connection with our acquisition of the Stroud terminal. Pursuant to the terms of the agreement, we receive a fixed amount per barrel from USDM in exchange for marketing the additional capacity available at the Stroud terminal. We also received revenue for providing additional terminalling services at our Hardisty terminal to USDM pursuant to the terms of its existing agreements with us. Additionally, effective January 2019, we entered into a six month terminalling services agreement with USDM at our Casper terminal to maximize utilization of available terminalling and storage capacity by offering these services to customers on an uncommitted basis at current market rates. This agreement automatically renews for successive periods of six months on an evergreen basis unless otherwise canceled by either party. We include amounts received pursuant to these arrangements as revenue in the table below under “Terminalling services — related party.” Additionally, we received revenue from USDM for the lease of 200 railcars pursuant to the terms of an existing agreement with us, which is included in the table below under “Fleet leases — related party.”

Our related party revenues from USD and affiliates are presented in the following table for the indicated periods:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands)
Terminalling services — related party	$	5,525	$	5,003	$	11,163	$	9,699
Fleet leases — related party	983		983		1,967		1,967
Fleet services — related party	228		228		455		455
Freight and other reimbursables — related party	—		2		61		4
	$	6,736	$	6,216	$	13,646	$	12,125

We had the following amounts outstanding with USD and affiliates on our consolidated balance sheets as presented below in the following table for the indicated periods:



	June 30, 2019		December 31, 2018
	(in thousands)
Accounts receivable — related party	$	1,317	$	624
Accounts payable — related party	$	83	$	67
Other current and non-current assets — related party ⁽¹⁾	$	134	$	174
Deferred revenue— related party ⁽²⁾	$	1,470	$	1,885


⁽¹⁾	Represents a contract asset associated with our lease agreement with USDM.


⁽²⁾	Represents deferred revenues associated with our terminalling and fleet services agreements with USD and affiliates for amounts we have collected from them for their prepaid leases and prepaid minimum volume commitment fees.

Cash Distributions

During the six months ended June 30, 2019 , we paid the following aggregate cash distributions to USDG as a holder of our common units and the sole owner of our subordinated units and to USD Partners GP LLC for its general partner interest and as the holder of our IDRs.



Distribution Declaration Date	Record Date	Distribution Payment Date	Amount Paid to USDG		Amount Paid to USD Partners GP LLC
			(in thousands)
January 31, 2019	February 11, 2019	February 19, 2019	$	4,161	$	285
April 26, 2019	May 7, 2019	May 15, 2019	$	4,189	$	308

14. COMMITMENTS AND CONTINGENCIES

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 such proceedings that will have a material adverse impact on our financial condition or results of operations.

15. SEGMENT REPORTING

We manage our business in two reportable segments: Terminalling services and Fleet services. The Terminalling services segment charges minimum monthly commitment fees under multi-year take-or-pay contracts to load and unload various grades of crude oil into and from railcars, as well as fixed fees per gallon to transload ethanol from railcars, including related logistics services. We also facilitate rail-to-pipeline shipments of crude oil. Our Terminalling services segment also charges minimum monthly fees to store crude oil in tanks that are leased to our customers. The Fleet services segment provides customers with railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels under multi-year, take-or-pay contracts. Corporate activities are not considered a reportable segment, but are included to present shared services and financing activities which are not allocated to our established reporting segments.

Our segments offer different services and are managed accordingly. Our chief operating decision maker, or CODM, regularly reviews financial information about both segments in order to allocate resources and evaluate performance. Our CODM assesses segment performance based on the cash flows produced by our established reporting segments using Segment Adjusted EBITDA. Segment Adjusted EBITDA is a measure calculated in accordance with GAAP. We define Segment Adjusted EBITDA as “Net income (loss)” of each segment adjusted for depreciation and amortization, interest, income taxes, deferred revenues, foreign currency transaction gains and losses and other items which do not affect the underlying cash flows produced by our businesses. As such, we have concluded that disaggregating revenue by reporting segments appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.



	Three Months Ended June 30, 2019
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	19,730		$	—	$	—		$	19,730
Terminalling services — related party	5,525			—		—			5,525
Fleet leases — related party	—			983		—			983
Fleet services	—			51		—			51
Fleet services — related party	—			228		—			228
Freight and other reimbursables	223			75		—			298
Freight and other reimbursables — related party	—			—		—			—
Total revenues	25,478			1,337		—			26,815
Operating costs
Subcontracted rail services	3,699			—		—			3,699
Pipeline fees	4,902			—		—			4,902
Freight and other reimbursables	223			75		—			298
Operating and maintenance	1,525			985		—			2,510
Selling, general and administrative	1,597			203		3,147			4,947
Depreciation and amortization	5,283			—		—			5,283
Total operating costs	17,229			1,263		3,147			21,639
Operating income (loss)	8,249			74		(3,147		)	5,176
Interest expense	—			—		2,982			2,982
Loss associated with derivative instruments	—			—		1,074			1,074
Foreign currency transaction loss (gain)	(54		)	4		70			20
Other expense (income), net	25			—		(4		)	21
Provision for income taxes	123			5		—			128
Net income (loss)	$	8,155		$	65	$	(7,269	)	$	951



	Three Months Ended June 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	22,511		$	—		$	—		$	22,511
Terminalling services — related party	5,003			—			—			5,003
Fleet leases — related party	—			983			—			983
Fleet services	—			81			—			81
Fleet services — related party	—			228			—			228
Freight and other reimbursables	547			222			—			769
Freight and other reimbursables — related party	1			1			—			2
Total revenues	28,062			1,515			—			29,577
Operating costs
Subcontracted rail services	3,311			—			—			3,311
Pipeline fees	5,118			—			—			5,118
Freight and other reimbursables	548			223			—			771
Operating maintenance	1,437			1,061			—			2,498
Selling, general and administrative	1,225			235			2,912			4,372
Depreciation and amortization	5,260			—			—			5,260
Total operating costs	16,899			1,519			2,912			21,330
Operating income (loss)	11,163			(4		)	(2,912		)	8,247
Interest expense	—			—			2,713			2,713
Gain associated with derivative instruments	—			—			(386		)	(386		)
Foreign currency transaction loss (gain)	31			(3		)	89			117
Other expense, net	1			—			—			1
Provision for (benefit from) income taxes	(899		)	(12		)	1			(910		)
Net income (loss)	$	12,030		$	11		$	(5,329	)	$	6,712



	Six Months Ended June 30, 2019
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	39,728		$	—		$	—		$	39,728
Terminalling services — related party	11,163			—			—			11,163
Fleet leases — related party	—			1,967			—			1,967
Fleet services	—			108			—			108
Fleet services — related party	—			455			—			455
Freight and other reimbursables	521			180			—			701
Freight and other reimbursables — related party	7			54			—			61
Total revenues	51,419			2,764			—			54,183
Operating costs
Subcontracted rail services	7,264			—			—			7,264
Pipeline fees	9,963			—			—			9,963
Freight and other reimbursables	528			234			—			762
Operating and maintenance	3,688			2,033			—			5,721
Selling, general and administrative	3,260			492			6,122			9,874
Depreciation and amortization	10,017			—			—			10,017
Total operating costs	34,720			2,759			6,122			43,601
Operating income (loss)	16,699			5			(6,122		)	10,582
Interest expense	—			—			6,169			6,169
Loss associated with derivative instruments	—			—			1,746			1,746
Foreign currency transaction loss (gain)	(95		)	8			289			202
Other expense (income), net	1			—			(4		)	(3		)
Provision for income taxes	190			8			—			198
Net income (loss)	$	16,603		$	(11	)	$	(14,322	)	$	2,270
Goodwill	$	33,589		$	—		$	—		$	33,589



	Six Months Ended June 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	44,516		$	—		$	—		$	44,516
Terminalling services — related party	9,699			—			—			9,699
Fleet leases — related party	—			1,967			—			1,967
Fleet services	—			425			—			425
Fleet services — related party	—			455			—			455
Freight and other reimbursables	760			1,484			—			2,244
Freight and other reimbursables — related party	3			1			—			4
Total revenues	54,978			4,332			—			59,310
Operating costs
Subcontracted rail services	6,373			—			—			6,373
Pipeline fees	10,842			—			—			10,842
Freight and other reimbursables	763			1,485			—			2,248
Operating and maintenance	2,728			2,126			—			4,854
Selling, general and administrative	2,787			560			5,849			9,196
Depreciation and amortization	10,536			—			—			10,536
Total operating costs	34,029			4,171			5,849			44,049
Operating income (loss)	20,949			161			(5,849		)	15,261
Interest expense	—			—			5,198			5,198
Gain associated with derivative instruments	—			—			(1,410		)	(1,410		)
Foreign currency transaction loss (gain)	62			(7		)	(149		)	(94		)
Other expense, net	72			—			—			72
Provision for (benefit from) income taxes	(1,834		)	16			1			(1,817		)
Net income (loss)	$	22,649		$	152		$	(9,489	)	$	13,312
Goodwill	$	33,589		$	—		$	—		$	33,589

Segment Adjusted EBITDA

The following tables present the computation of Segment Adjusted EBITDA for each of our segments for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
Terminalling Services Segment	2019			2018			2019			2018
	(in thousands)
Net income	$	8,155		$	12,030		$	16,603		$	22,649
Interest income	(8		)	—			(15		)	—
Depreciation and amortization	5,283			5,260			10,017			10,536
Provision for (benefit from) income taxes	123			(899		)	190			(1,834		)
Foreign currency transaction loss (gain) ⁽¹⁾	(54		)	31			(95		)	62
Loss associated with disposal of assets	42			2			50			73
Other income	(25		)	—			(42		)	—
Non-cash contract asset ⁽²⁾	(52		)	(52		)	(103		)	(103		)
Deferred revenue associated with deficiency credits ⁽³⁾	213			—			213			—
Segment Adjusted EBITDA	$	13,677		$	16,372		$	26,818		$	31,383


⁽¹⁾	Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.


⁽²⁾	Represents the change in non-cash contract assets associated with revenue recognized in advance at blended rates based on the escalation clauses in certain of our customer contracts. Refer to Note 4. Revenues — Contract Assets for more information.


⁽³⁾	Represents deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.



	Three Months Ended June 30,					Six Months Ended June 30,
Fleet Services Segment	2019		2018			2019			2018
	(in thousands)
Net income (loss)	$	65	$	11		$	(11	)	$	152
Provision for (benefit from) income taxes	5		(12		)	8			16
Foreign currency transaction loss (gain) ⁽¹⁾	4		(3		)	8			(7		)
Segment Adjusted EBITDA	$	74	$	(4	)	$	5		$	161


⁽¹⁾	Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.

16. INCOME TAXES

U.S. Federal and State Income Taxes

We are treated as a partnership for U.S. federal and most state income tax purposes, with each partner being separately taxed on their share of our taxable income. We have elected to classify one of our subsidiaries, USD Rail LP, as an entity taxable as a corporation for U.S. federal income tax purposes due to treasury regulations that do not permit the income of this subsidiary to meet the definition of “qualifying income” as set forth in Internal Revenue Code §7704(d). We are also subject to state franchise tax in the state of Texas, which is treated as an income tax under the applicable accounting guidance. Our U.S. federal income tax expense is based on the statutory federal income tax rate of 21% , as applied to USD Rail LP’s taxable losses of $0.1 million and $0.2 million for the three months ended June 30, 2019 and 2018 , respectively, and losses of $0.2 million and $0.4 million for the six months ended June 30, 2019 and 2018 , respectively.

Foreign Income Taxes

Our Canadian operations are conducted through entities that are subject to Canadian federal and Alberta provincial income taxes. The Canadian federal income tax on business income is currently 15% . In June 2019, the Canadian province of Alberta enacted a tax rate decrease that will reduce the tax rate on business income from the previous rate of 12% to an ultimate rate of 8% effective for 2022. The reduction in the tax rate on business income is phased in over three years beginning with a reduction to a rate of 11% effective July 1, 2019, with further reductions of 1% in each successive year until it reaches 8% on January 1, 2022. As a result, the effective tax rate on business income on Alberta businesses for 2019 will be 11.5% , representing a blended rate of 12% from January 1, 2019 through June 30, 2019, and 11% from July 1, 2019 through December 31, 2019.

We recognize income tax expense in our consolidated financial statements based upon enacted rates in effect for the periods presented. As such for the three and six months ended June 30, 2019 , income tax expense for our Canadian operations is determined based upon the combined federal and provincial income tax rate of 26.5% , representing a 15% federal income tax rate and a 11.5% provincial income tax rate. For the three and six months ended June 30, 2018 , income tax expense of our Canadian operations was determined based on the combined federal and provincial income tax rate of 27% . The combined income tax rate of 23% , representing a 15% federal income tax rate and an 8% provincial income tax rate, was used to compute the deferred income tax benefit, representing the impact of temporary differences that are expected to reverse in the future.

Estimated Annual Effective Income Tax Rate

The following table presents a reconciliation of our income tax based on the U.S. federal statutory income tax rate and our effective income tax rate:



	Three Months Ended June 30,										Six Months Ended June 30,
	2019					2018					2019					2018
	(in thousands)
Income tax expense at the U.S. federal statutory rate	$	226		21	%	$	1,219		21	%	$	518		21	%	$	2,414		21	%
Amount attributable to partnership not subject to income tax	(107		)	(10	)%	(1,909		)	(33	)%	(372		)	(15	)%	(3,901		)	(34	)%
Foreign income tax rate differential	40			4	%	(188		)	(3	)%	63			3	%	(386		)	(3	)%
Other	(53		)	(5	)%	(52		)	—	%	(53		)	(2	)%	(44		)	—	%
State income tax expense	5			1	%	(16		)	—	%	8			—	%	(6		)	—	%
Change in valuation allowance	17			2	%	36			—	%	34			1	%	106			1	%
Provision for (benefit from) income taxes	$	128		13	%	$	(910	)	(15	)%	$	198		8	%	$	(1,817	)	(15	)%

We determined our year-to-date 2019 provision for income taxes using an estimated annual effective income tax rate of 8% on a consolidated basis for fiscal year 2019 . This rate incorporates the applicable income tax rates of the various domestic and foreign tax jurisdictions to which we are subject.



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)
Current income tax expense (benefit):
U.S. federal income tax	$	—		$	4		$	—		$	4
State income tax expense (benefit)	5			(16		)	8			(6		)
Canadian federal and provincial income taxes expense	277			350			593			723
Total current income tax expense	282			338			601			721
Deferred income tax expense (benefit):
U.S. federal income tax expense	—			—			—			16
Canadian federal and provincial income taxes benefit	(154		)	(1,248		)	(403		)	(2,554		)
Total deferred income tax benefit	(154		)	(1,248		)	(403		)	(2,538		)
Provision for (benefit from) income taxes	$	128		$	(910	)	$	198		$	(1,817	)

Our deferred income tax assets and liabilities reflect the income tax effect of differences between the carrying amounts of our assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Major components of deferred income tax assets and liabilities associated with our operations were as follows as of the dates indicated:



	June 30, 2019
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Property and equipment	$	—		$	268		$	268
Capital loss carryforwards	—			368			368
Operating loss carryforwards	217			—			217
Deferred income tax liabilities
Unbilled revenue	—			(233		)	(233		)
Prepaid expenses	(10		)	—			(10		)
Property and equipment	—			—			—
Valuation allowance	(207		)	(368		)	(575		)
Deferred income tax asset, net	$	—		$	35		$	35



	December 31, 2018
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Capital loss carryforwards	$	—		$	432		$	432
Operating loss carryforwards	183			—			183
Deferred income tax liabilities
Unbilled revenue	—			(336		)	(336		)
Prepaid expenses	(10		)	—			(10		)
Property and equipment	—			(24		)	(24		)
Valuation allowance	(173		)	(432		)	(605		)
Deferred income tax liability, net	$	—		$	(360	)	$	(360	)

We had a $1.0 million and $0.9 million U.S. federal loss carryforward remaining as of June 30, 2019 and December 31, 2018 , respectively. Our U.S. federal loss carryforward was generated in 2018 and 2019 and does not expire under currently enacted tax law. Our Canadian loss carryforward was $4.4 million and $4.2 million as of June 30, 2019 and December 31, 2018 , respectively. A portion of our Canadian loss carryforward is for capital items

that do not expire under currently enacted Canadian tax law, the remaining Canadian operating loss of $1.1 million will expire in 2034.

We are subject to examination by the taxing authorities for the years ended December 31, 2017 , 2016 and 2015 . We did no t have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of June 30, 2019 and December 31, 2018 .

Refer to Note 20. Supplemental Cash Flow Information for information regarding amounts paid for income taxes.

17. DERIVATIVE FINANCIAL INSTRUMENTS

Our net income and cash flows are subject to fluctuations resulting from changes in interest rates on our variable rate debt obligations and from changes in foreign currency exchange rates, particularly with respect to the U.S. dollar and the Canadian dollar. In limited circumstances, we may also hold long positions in the commodities we handle on behalf of our customers, which exposes us to commodity price risk. We use derivative financial instruments, including futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates, foreign currency exchange rates and commodity prices, as well as to reduce volatility in our cash flows. We have not historically designated, nor do we expect to designate, our derivative financial instruments as hedges of the underlying risk exposure. 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.

Interest Rate Derivatives

We use interest rate derivative financial instruments to partially mitigate our exposure to interest rate fluctuations on our variable rate debt. Under our Credit Agreement, one-month LIBOR is used as the index rate for the interest we are charged on amounts borrowed under our Revolving Credit Facility. Effective November 2017, we entered into a five -year interest rate collar contract with a $100 million notional amount. The collar establishes a range where we will pay the counterparty if the one-month Overnight Index Swap, or OIS, rate falls below the established floor rate of 1.7% , and the counterparty will pay us if the one-month OIS rate exceeds the established ceiling rate of 2.5% . The collar settles monthly through the termination date in October 2022. No payments or receipts are exchanged on the interest rate collar contracts unless interest rates rise above or fall below the pre-determined ceiling or floor rates. Prior to February 2019, our interest rate collar contract discussed above was based on one-month LIBOR, which is being phased out by financial institutions in the United States.

Derivative Positions

We record all of our derivative financial instruments at their fair values in the line items specified below within our consolidated balance sheets, the amounts of which were as follows at the dates indicated:



	June 30, 2019			December 31, 2018
	(in thousands)
Other current assets	$	—		$	260
Other non-current assets	—			335
Other current liabilities	(135		)	—
Other non-current liabilities	(1,017		)	—
	$	(1,152	)	$	595

We have not designated our derivative financial instruments as hedges of our interest rate or foreign currency exposures. As a result, changes in the fair value of these derivatives are recorded as “Loss (gain) associated with derivative instruments” in our consolidated statements of income. The gains or losses associated with changes in the fair value of our 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. In connection with our derivative activities, we recognized the following amounts during the periods presented:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019		2018
	(in thousands)
Loss (gain) associated with derivative instruments	$	1,074	$	(386	)	$	1,746	$	(1,410	)

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 interest rate contracts for the periods indicated:



					At June 30, 2019			At December 31, 2018
	Notional		Interest Rate Parameters		Fair Value			Fair Value
					(in thousands)
Collar Agreements Maturing in 2022
Ceiling	$	100,000,000	2.5	%	$	202		$	1,238
Floor	$	100,000,000	1.7	%	(1,354		)	(643		)
Total					$	(1,152	)	$	595

We record the fair market value of our derivative financial instruments in our consolidated balance sheets as current and non-current assets or liabilities on a net basis by counterparty. The terms of the International Swaps and Derivatives Association, or ISDA, Master Agreement governs our financial contracts and include master netting agreements that allow the parties to our derivative contracts to elect net settlement in respect of all transactions under the agreements. The effect of the rights of offset are presented in the tables below as of the dates indicated.



	June 30, 2019
	Current assets			Non-current assets			Current liabilities			Non-current liabilities			Total
	(in thousands)
Fair value of derivatives — gross presentation	$	7		$	195		$	(142	)	$	(1,212	)	$	(1,152	)
Effects of netting arrangements	(7		)	(195		)	7			195			—
Fair value of derivatives — net presentation	$	—		$	—		$	(135	)	$	(1,017	)	$	(1,152	)



	December 31, 2018
	Current assets		Non-current assets			Current liabilities		Non-current liabilities			Total
	(in thousands)
Fair value of derivatives — gross presentation	$	260	$	978		$	—	$	(643	)	$	595
Effects of netting arrangements	—		(643		)	—		643			—
Fair value of derivatives — net presentation	$	260	$	335		$	—	$	—		$	595

18. PARTNERS’ CAPITAL

Our 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 to exercise the rights and privileges available to limited partners under our partnership agreement.

In February 2019 , pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested and was converted into our common units. We determined that each vested Class A unit would receive one common unit at conversion based upon our distributions paid for the four preceding quarters. As a result, the final tranche of 38,750 Class A units were converted into 38,750 common units and no Class A units remain outstanding at June 30, 2019. Our Class A units were limited partner interests in us that entitled the holders to nonforfeitable distributions that were equivalent to the distributions paid with respect to our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and, as a result, were considered participating securities. Our Class A units did not have voting rights and vested in four equal annual installments over the four years following the consummation of our initial public offering, or IPO, only if we grew our annualized distributions each year. If we did not achieve positive distribution growth in any of those years, the Class A units that would otherwise vest for that year would be forfeited. The Class A units contained a conversion feature, which, upon vesting, provided for the conversion of the Class A units into common units based on a conversion factor that was tied to the level of our distribution growth for the applicable year. The conversion factor was 1.00 for the first vesting tranche, 1.50 for the second vesting tranche, 1.00 for the third vesting tranche and 1.00 for the fourth vesting tranche.

Our partnership agreement provides that, while any subordinated units remain outstanding, holders of our common 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 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 convert into common units on a one -for-one basis in separate sequential tranches. Each tranche is comprised of 20.0% of the subordinated units issued in conjunction with our IPO. Each separate tranche is eligible to convert on or after December 31, 2015 (but no more frequently than once in any twelve -month period), provided on such 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) there are no arrearages in the payment of the minimum quarterly distribution on our 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. In February 2019 , pursuant to the terms set forth in our partnership agreement, we converted the fourth tranche of 2,092,709 of our subordinated units into common units upon satisfaction of the conditions established for conversion.

Pursuant to the terms of the USD Partners LP Amended and Restated 2014 Long-Term Incentive Plan, which we refer to as the A/R LTIP, our phantom unit awards, or Phantom Units, granted to directors and employees of our general partner and its affiliates, which are classified as equity, are converted into our common units upon vesting. Equity-classified Phantom Units totaling 451,959 vested during the first six months of 2019 , of which 362,743 were converted into our common units after 162,533 Phantom Units were withheld from participants for the payment of applicable employment-related withholding taxes. The conversion of these Phantom Units did not have any economic impact on Partners’ Capital, since the economic impact is recognized over the vesting period. Additional information and discussion regarding our unit based compensation plans is included below in Note 19. Unit Based Compensation .

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 are determined by our general partner.

19. UNIT BASED COMPENSATION

Class A units

Our Class A units vested annually over a four year period if established distribution growth target thresholds were met during each year of the four year vesting period. In February 2019 , pursuant to the terms set forth in our partnership agreement, the fourth and final vesting tranche of 38,750 Class A units vested based upon our distributions paid for the four preceding quarters and were converted on a basis of one common unit for each Class A unit. As a result, we converted 38,750 Class A units into 38,750 common units and no Class A units remain outstanding at June 30, 2019 .

The following table presents the activity associated with our Class A units for the specified periods:



	Six Months Ended June 30,
	2019		2018
Class A units outstanding at beginning of period	38,750		82,500
Vested	(38,750	)	(38,750	)
Forfeited	—		(5,000	)
Class A units outstanding at end of period	—		38,750

We recognized compensation expense in “Selling, general and administrative” with regard to our Class A units for the following amounts during the periods presented:



	Three Months Ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(in thousands)
Selling, general and administrative	$	—	$	104	$	14	$	174

For the three and six months ended June 30, 2019 and the three months ended June 30, 2018 we had no forfeitures of Class A units. For the six months ended June 30, 2018 , we had forfeitures of 5,000 Class A units. We elected to account for actual forfeitures as they occurred rather than applying an estimated forfeiture rate when determining compensation expense.

Each holder of a Class A unit was entitled to nonforfeitable cash distributions equal to the product of the number of Class A units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions are included in “Distributions” as presented in our consolidated statements of cash flows and our consolidated statement of partners’ capital. However, any distributions paid on Class A units that were forfeited were reclassified to unit based compensation expense when we determined that the Class A units were not expected to vest. We recognized no compensation expense for the three and six months ended June 30, 2019 and the three months ended June 30, 2018 , for distributions paid on Class A units that were forfeited. For the six months ended June 30, 2018 , we recognized compensation expense of $15 thousand for distributions paid on forfeited Class A units.

Long-term Incentive Plan

In 2019 and 2018 , the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 633,637 and 553,940 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At June 30, 2019 , we had 1,381,649 Phantom Units remaining available for grant pursuant to the terms of our A/R LTIP. The Phantom Units are subject to all of the terms and conditions of the A/R LTIP and the Phantom Unit award agreements, which are collectively referred to as the Award Agreements.

Award amounts for each of the grants are generally determined by reference to a specified dollar amount 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 a closing price of one of our common units preceding the grant date, as determined by the board of directors of our general partner and quoted on the NYSE.

Phantom Unit awards generally represent rights to receive our common units upon vesting. However, with respect to the awards granted to directors and employees of our general partner and its affiliates domiciled in Canada, for each Phantom Unit that vests, a participant is entitled to receive cash for an amount equivalent to the closing market price of one of our common units on the vesting date. Each Phantom Unit granted under the Award Agreements includes an accompanying distribution equivalent right, or DER, which entitles each participant to receive payments at a per unit rate equal in amount to the per unit rate for any distributions we make with respect to our common units. The Award Agreements granted to employees of our general partner and its affiliates generally contemplate that the 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 and an independent consultant typically vest over a one year period following the grant date.

The following tables present the award activity for our Equity-classified Phantom Units:



	Director and Independent Consultant Phantom Units		Employee Phantom Units		Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2018	34,611		1,130,685		$	11.19
Granted	37,139		544,857		$	11.37
Vested	(34,611	)	(417,348	)	$	11.00
Forfeited	—		(2,859	)	$	10.94
Phantom Unit awards at June 30, 2019	37,139		1,255,335		$	11.34



	Director and Independent Consultant Phantom Units		Employee Phantom Units		Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2017	24,999		1,111,849		$	10.90
Granted	34,611		487,839		$	11.54
Vested	(24,999	)	(336,571	)	$	10.86
Forfeited	—		(56,740	)	$	11.07
Phantom Unit awards at June 30, 2018	34,611		1,206,377		$	11.18

The following tables present the award activity for our Liability-classified Phantom Units:



	Director and Independent Consultant Phantom Units		Employee Phantom Units	Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2018	11,348		29,265	$	11.31
Granted	12,177		39,464	$	11.37
Vested	(11,348	)	—	$	11.55
Phantom Unit awards at June 30, 2019	12,177		68,729	$	11.32



	Director and Independent Consultant Phantom Units		Employee Phantom Units	Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2017	8,333		27,794	$	11.29
Granted	11,348		20,142	$	11.55
Vested	(8,333	)	—	$	12.80
Phantom Unit awards at June 30, 2018	11,348		47,936	$	12.13

The fair value of each Phantom Unit on the grant date is equal to the closing market price of our common units on the grant date. We account for the Phantom Unit grants to independent directors and employees of our general partner and its affiliates domiciled in Canada that are paid out in cash upon vesting, throughout the requisite vesting period, by revaluing the unvested Phantom Units outstanding at the end of each reporting period and recording a charge to compensation expense in “Selling, general and administrative” in our consolidated statements of income and recognizing a liability in “Other current liabilities” in our consolidated balance sheets. With respect to the Phantom Units granted to consultants, independent directors and employees of our general partner and its affiliates domiciled in the United States, we amortize the initial grant date fair value over the requisite service period using the straight-line method with a charge to compensation expense in “Selling, general and administrative” in our consolidated statements of income, with an offset to common units within the Partners’ Capital section of our consolidated balance sheet.

For the three months ended June 30, 2019 and 2018 , we recognized $1.6 million and $1.5 million , respectively, and $3.0 million and $2.7 million for the six months ended June 30, 2019 and 2018 , respectively, of compensation expense associated with outstanding Phantom Units. As of June 30, 2019 , we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $13.3 million , which we expect to recognize over a weighted average period of 2.74 years. We have elected to account for actual forfeitures as they occur rather than using an estimated forfeiture rate to determine the number of awards we expect to vest.

We made payments to holders of the Phantom Units pursuant to the associated DERs we granted to them under the Award Agreements as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands)
Equity-classified Phantom Units ⁽¹⁾	$	469	$	441	$	887	$	829
Liability-classified Phantom Units	29		21		44		34
Total	$	498	$	462	$	931	$	863


⁽¹⁾	We reclassified $39 thousand for the three months ended June 30, 2018 and $7 thousand and $84 thousand for the six months ended June 30, 2019 and 2018 , respectively, to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited. We had no forfeitures for the three months ended June 30, 2019 .

20. SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental cash flow information for the periods indicated:



	Six Months Ended June 30,
	2019		2018
	(in thousands)
Cash paid for income taxes	$	607	$	449
Cash paid for interest	$	5,815	$	4,821
Cash paid for operating leases ⁽¹⁾	$	3,058	$	—

⁽¹⁾ Our adoption of ASC 842 was as of January 1, 2019. There is no comparable disclosure for the prior year under ASC 840.

The following table provides supplemental information for the item labeled “Other” in the “Net cash provided by operating activities” section of our consolidated statements of cash flows:



	Six Months Ended June 30,
	2019		2018
	(in thousands)
Loss associated with disposal of assets	$	50	$	73
Amortization of deferred financing costs	657		430
	$	707	$	503

Non-cash activities

During the six months ended June 30, 2019 , we had capital expenditures of $2.3 million for which payment had not been made included in accounts payable and accrued expenses.

We recorded $17.3 million of right-of-use lease assets and the associated liabilities on our consolidated balance sheet as of January 1, 2019, representing non-cash activities resulting from our adoption and implementation of ASC 842, Leases. See Note 2. Recent Accounting Pronouncements and Note 8. Leases for further discussion.

21. SUBSEQUENT EVENTS

Distribution to Partners

On July 24, 2019 , the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.365 per unit, or $1.46 per unit on an annualized basis, for the three months ended June 30, 2019 . The distribution represents an increase of $0.0025 per unit, or 0.7% over the prior quarter distribution per unit, and is 27.0% over our minimum quarterly distribution per unit. The distribution will be paid on August 14, 2019 , to unitholders of record at the close of business on August 6, 2019 . The distribution will include payment of $5.5 million to our public common unitholders, an aggregate of $4.2 million to USDG as a holder of our common units and the sole owner of our subordinated units and $329 thousand to USD Partners GP LLC for its general partner interest and as holder of the IDRs.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with the unaudited consolidated financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our audited consolidated financial statements and accompanying notes included in “ Item 8. Financial Statements and Supplementary Data ” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 . Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following discussion and analysis. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in “ Item 1A. Risk Factors ” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and subsequent Quarterly Reports on Form 10-Q. Please also read the “ Cautionary Note Regarding Forward-Looking Statements ” following the table of contents in this Report.

We denote amounts denominated in Canadian dollars with “ C$ ” immediately prior to the stated amount.

Overview

We are a fee-based, growth-oriented master limited partnership formed by our sponsor, USD, to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products. We generate substantially all of our operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies, refiners and marketers. Our network of crude oil terminals facilitates the transportation of heavy crude oil from Western Canada to key demand centers across North America. Our operations include railcar loading and unloading, storage and blending in on-site tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. We also provide our customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail.

We generally do not take ownership of the products that we handle, nor do we receive any payments from our customers based on the value of such products. On occasion we enter into buy-sell arrangements in which we take temporary title to commodities while in our terminals. We expect any such arrangements to be at fixed prices where we do not take commodity price exposure.

We believe rail will continue as an important transportation option for energy producers, refiners and marketers due to its unique advantages relative to other transportation means. Specifically, rail transportation of energy-related products provides flexible access to key demand centers on a relatively low fixed-cost basis with faster physical delivery, while preserving the specific quality of customer products over long distances.

USDG, a wholly-owned subsidiary of USD and the sole owner of our general partner, is engaged in designing, developing, owning, and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USDG’s solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the U.S. Gulf Coast and Mexico. Among other projects, USDG is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities. USDG completed an expansion project in January 2019 at the Partnership's Hardisty terminal, which we refer to as Hardisty South, which added one 120-railcar unit train of transloading capacity per day, or approximately 75,000 barrels per day, or bpd.

Recent Developments

Market Update

Substantially all of our operating cash flows are generated from take-or-pay contracts and, as a result, are not directly related to actual throughput volumes at our crude oil terminals. Throughput volumes at our terminals are primarily influenced by the difference in price between Western Canadian Select, or WCS, and other grades of crude oil, commonly referred to as spreads, rather than absolute price levels. WCS spreads are influenced by several market

factors, including the availability of supplies relative to the level of demand from refiners and other end users, the price and availability of alternative grades of crude oil, the availability of takeaway capacity, as well as transportation costs from supply areas to demand centers.

In December 2018, the Alberta Government announced that it would curtail crude oil and bitumen production by 325,000 bpd beginning January 1, 2019. The Alberta Government’s objective was to reduce inventory levels to a targeted level to ensure more economical prices for WCS. Once the targeted inventory and return levels are achieved, the curtailment is expected to be reduced to approximately 95,000 bpd. During 2019 to date, the Alberta Government has announced reductions to the curtailment level as depicted in the following chart:



Production Month		Curtailment Level (Barrels per day)
February 2019		250,000
April 2019		225,000
May 2019		200,000
June 2019		175,000
August 2019		150,000

To address the current pipeline capacity constraints from Western Canada and to increase Alberta’s overall export capacity, the Alberta Government also announced an initiative to increase rail capacity in order to export WCS to markets with more economical returns. This initiative included leasing approximately 4,400 new rail cars to move up to 120,000 bpd of crude oil by 2020, as well as agreements for terminalling services (including an agreement with USDG) and rail transportation contracts. In June 2019, the Alberta Government announced that they have engaged CIBC Capital Markets to help oversee the divestment of this crude-by-rail program and its transition to the private sector. The Alberta Government has stated that it expects the process to be completed by the Fall of 2019.

In response to the Alberta Government’s efforts discussed above, the WCS to West Texas Intermediate, or WTI, crude oil spread narrowed to between $7-$17 per barrel to date in 2019 from $11-$50 per barrel during the fourth quarter of 2018. Despite the Alberta Government’s efforts, to date in 2019 apportionment levels on the primary heavy and light crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. have averaged approximately 40% (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints) and inventory levels have remained high.

We expect the WCS to WTI spread to widen to levels that will require increasing takeaway capacity from crude by rail as Western Canadian production continues to grow and pipeline takeaway capacity out of the region remains constrained. Future WCS versus WTI spreads published by Bloomberg through 2023 average approximately $21 per barrel and are indicative of the continued expected imbalance between supply and takeaway capacity. The latest data available as published by the U.S. Energy Information Administration, or EIA, indicates Canadian crude-by-rail imports into the United States increased to approximately 250,000 bpd through April 2019 on a year-to-date basis. This represents an approximate 61% increase in crude-by-rail imports from Canada into the United States over the 2018 comparative period and a 5% increase over the 2018 yearly average. As such, based on current customer indications, we expect future demand for and utilization of our terminals to be higher.

Western Canadian crude oil production is projected to continue to increase throughout the next decade, driven primarily by developments in Alberta’s oil sands region. In June 2019, the Canadian Association of Petroleum Producers, or CAPP, projected that the supply of crude oil from Western Canada will grow by approximately 350,000 bpd by 2020 and 1.2 million bpd by 2030 relative to 2018 levels. The forecasted supply of crude oil from Western Canada remains well in excess of existing pipeline takeaway capacity out of the region. Pipeline export capacity from Western Canada remains constrained and projects to increase export capacity have continued to experience significant regulatory delays. For example, the anticipated in-service date of Enbridge Inc.’s Line 3 Replacement project to upgrade and expand an existing pipeline delivering Western Canadian crude to U.S. markets was changed from late 2019 to the second half of 2020, due to a revised construction schedule.

In prior years, the industry has experienced a consolidation of Western Canadian oil sands producing assets among active Canadian producers. We expect this will continue to drive further expansions of crude oil production capacity, particularly at existing projects, as cost savings and technological advancements made during the recent commodity price downturn are incorporated into future development plans.

We expect demand for rail capacity at our terminals to increase over the next several years and potentially longer if proposed pipeline developments do not meet currently planned timelines and regulatory or other challenges persist. Our Hardisty and Casper terminals, with established capacity and scalable designs, are well-positioned as strategic outlets to meet growing takeaway needs as Western Canadian crude oil supplies continue to exceed available pipeline takeaway capacity. Additionally, we believe our Stroud terminal provides an advantageous rail destination for Western Canadian crude oil given the optionality provided by its connectivity to the Cushing hub and multiple refining centers across the United States. Rail also generally provides a greater ability to preserve the specific quality of a customer’s product relative to pipelines, providing value to a producer or refiner. We expect these advantages, including our recently established origin-to-destination capabilities, to continue to result in long-term contract extensions and expansion opportunities across our terminal network.

Commercial Developments

Hardisty Terminal

In the first quarter of 2019, USDG executed a new multi-year, take-or-pay terminalling services agreement with the Alberta Petroleum Marketing Commission, or APMC, an agent of the Government of Alberta. The agreement is for transloading capacity at the Hardisty rail terminal starting in January 2020 and contains take-or-pay terms with minimum monthly payments. The agreement supports further expansion at USDG’s Hardisty South development and is expected to provide incremental capacity beyond the APMC commitment. This expansion will be funded and owned by USDG, pursuant to its development rights at the Hardisty terminal. We do not anticipate that the Alberta Government’s plan to divest the crude-by-rail program (of which this agreement is a part) to the private sector, as discussed above, will result in a material decrease in the economic value of this agreement to USDG.

In July 2019, we and an investment grade customer entered into a multi-year renewal and extension of the terminalling services agreement that covers approximately 15% of the capacity at the Hardisty rail terminal. The renewal was effective from the expiration date of the original agreement in June 2019. The renewal contains take-or-pay arrangements that are generally consistent with the original agreement and monthly payments and fees that are slightly higher. We expect to service the contract by using the limited remaining capacity available at the Hardisty terminal, as well as by subletting excess capacity from USDG’s Hardisty South Expansion. With this recent contract renewal, the Partnership’s Hardisty terminal is effectively 100% contracted at full capacity through June 2020. To date, the Partnership has replaced approximately 83% of the Hardisty terminal’s current cash flows, on an annualized basis over the next three years starting in July 2019, with the balance coming up for renewal in February and July of 2020.

Additionally, in connection with the Hardisty agreement described above, the same customer entered into a multi-year renewal and extension of the terminalling services agreement with USDM that covers approximately 30% of the destination capacity at the Stroud terminal. The renewal was effective from the expiration date of the original agreement in June 2019. This agreement is subject to the Marketing Services Agreement established between USDM and us at the time of the Stroud acquisition, pursuant to which USDM will pay us a nominal fee for all throughput under this agreement in excess of the throughput necessary for the Stroud terminal to generate Adjusted EBITDA that is at least equal to the average monthly Adjusted EBITDA derived from the initial Stroud terminal customer, which nominal fee generally covers our costs to operate the Stroud terminal.

Casper Terminal

The Casper terminal receives inbound crude oil primarily through our dedicated direct pipeline connection from the Express Pipeline, which is subsequently loaded onto unit or manifest trains. To supplement rail loading operations from the terminal, we are currently constructing the previously announced outbound pipeline connection from the Casper Terminal to a nearby terminal located at the termination point of the Express pipeline. The construction of the outbound pipeline connection is expected to be complete in late November 2019.

In addition, Enbridge recently announced a program to increase the capacity of the Express pipeline by up to an additional 50,000 bpd with the use of drag reducing agent, or DRA, and pump stations. The open season for the expanded capacity on the Express pipeline is currently scheduled to conclude on August 23, 2019. Upon a successful open season, the additional volumes could begin shipping in early 2020. We anticipate that some of the additional volumes resulting from the increased capacity on the Express pipeline could be delivered to our Casper terminal, as we believe outbound pipeline connections from the Express pipeline and nearby terminals are at or near full capacity.

How We Generate Revenue

We conduct our business through two distinct reporting segments: Terminalling services and Fleet services. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to assist in resource allocation decisions and to assess operational performance.

Terminalling Services

The terminalling services segment includes a network of strategically-located terminals that provide customers with railcar loading and/or unloading capacity, as well as related logistics services, for crude oil and biofuels. Substantially all of our cash flows are generated under multi-year, take-or-pay terminal services agreements that include minimum monthly commitment fees.

Our Hardisty terminal, which commenced operations in late June 2014, is an origination terminal where we load into railcars various grades of Canadian crude oil received from Gibson’s Hardisty storage terminal. Our Hardisty terminal can load up to two 120-railcar unit trains per day and consists of a fixed loading rack with approximately 30 railcar loading positions, a unit train staging area and loop tracks capable of holding five unit trains simultaneously.

Our Stroud terminal is a crude oil destination terminal in Stroud, Oklahoma, which we use to facilitate rail-to-pipeline shipments of crude oil from our Hardisty terminal to the crude oil storage hub located in Cushing, Oklahoma. The Stroud terminal includes 76-acres with current unit train unloading capacity of approximately 50,000 Bpd, two onsite tanks with 140,000 barrels of capacity, one truck bay, and a 12-inch diameter, 17-mile pipeline with a direct connection to the crude oil storage hub in Cushing Oklahoma. Our Stroud terminal was purchased in June 2017 and commenced operations in October 2017.

Our Casper terminal, which we acquired in November 2015, is a crude oil storage, blending and railcar loading terminal. The terminal currently offers six storage tanks with 900,000 bbls of total capacity, unit train-capable railcar loading capacity in excess of 100,000 bpd, as well as truck transloading capacity. Our Casper terminal is supplied with multiple grades of Canadian crude oil through a direct connection with the Express Pipeline. Additionally, the Casper terminal has a connection from the Platte terminal, where it has access to other pipelines and can receive other grades of crude oil, including locally sourced Wyoming sour crude oil. The Casper terminal can also receive volumes through one truck unloading station and is also equipped with one truck loading station. In connection with an agreement that was executed in 2018, we are constructing an outbound pipeline connection from the Casper terminal to complement our existing inbound pipeline connection and we may construct additional storage tanks to facilitate blending and staging operations for our customers, if needed. However, if the outbound pipeline is not completed by the end of 2019, then pursuant to the agreement, our customer may gain the right to terminate all or portions of the agreement. We expect to complete the construction of the pipeline by the end of November 2019.

Our West Colton terminal, completed in November 2009, is a unit train-capable destination terminal that can transload up to 13,000 bpd of ethanol received from producers by rail onto trucks to meet local demand in the San Bernardino and Riverside County-Inland Empire region of Southern California. The West Colton terminal has 20 railcar offloading positions and three truck loading positions.

Fleet Services

We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on multi-year, take-or-pay terms under master fleet services agreements for initial periods ranging from five to nine years. We do not own any railcars. As of June 30, 2019 , our railcar fleet consisted of

1,683 railcars, which we leased from various railcar manufacturers and financial entities, including 1,308 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,483 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars. The weighted average remaining contract life on our railcar fleet is 2.8 years as of June 30, 2019 .

Under the master fleet services agreements, we provide customers with railcar-specific fleet services, which may include, among other things, the provision of relevant administrative and billing services, the repair and maintenance of railcars in accordance with standard industry practice and applicable law, the management and tracking of the movement of railcars, the regulatory and administrative reporting and compliance as required in connection with the movement of railcars, and the negotiation for and sourcing of railcars. Our customers typically pay us and our assignees monthly fees per railcar for these services, which include a component for railcar use and a component for fleet services.

How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to evaluate our operations. We consider these metrics to be significant factors in assessing our ability to generate cash and pay distributions and include: (i) Adjusted EBITDA and DCF; (ii) operating costs; and (iii) volumes. We define Adjusted EBITDA and DCF below.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as “Net cash provided by operating activities” adjusted for changes in working capital items, interest, income taxes, foreign currency transaction gains and losses, and other items which do not affect the underlying cash flows produced by our businesses. Adjusted EBITDA is a non-GAAP, supplemental financial measure used by management and external users of our financial statements, such as investors and commercial banks, to assess:


•	our liquidity and the ability of our business to produce sufficient cash flow to make distributions to our unitholders; and


•	our ability to incur and service debt and fund capital expenditures.

We define Distributable Cash Flow, or DCF, as Adjusted EBITDA less net cash paid for interest, income taxes and maintenance capital expenditures. DCF does not reflect changes in working capital balances. DCF is a non-GAAP, supplemental financial measure used by management and by external users of our financial statements, such as investors and commercial banks, to assess:


•	the amount of cash available for making distributions to our unitholders;


•	the excess cash flow being retained for use in enhancing our existing business; and


•	the sustainability of our current distribution rate per unit.

We believe that the presentation of Adjusted EBITDA and DCF in this report provides information that enhances an investor’s understanding of our ability to generate cash for payment of distributions and other purposes. The GAAP measure most directly comparable to Adjusted EBITDA and DCF is “Net cash provided by operating activities.” Adjusted EBITDA and DCF should not be considered as alternatives to “Net cash provided by operating activities” or any other measure of liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF exclude some, but not all, items that affect “Net cash provided by operating activities,” and these measures may vary among other companies. As a result, Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	9,336		$	11,484		$	19,507		$	19,588
Add (deduct):
Amortization of deferred financing costs	(207		)	(215		)	(657		)	(430		)
Deferred income taxes	154			1,248			403			2,538
Changes in accounts receivable and other assets	3,134			(863		)	2,298			6,414
Changes in accounts payable and accrued expenses	(1,221		)	(4,243		)	(2,009		)	(2,978		)
Changes in deferred revenue and other liabilities	(2,264		)	5,735			(2,462		)	236
Interest expense, net	2,970			2,713			6,150			5,198
Provision for (benefit from) income taxes	128			(910		)	198			(1,817		)
Foreign currency transaction loss (gain) ⁽¹⁾	20			117			202			(94		)
Other income	(25		)	—			(42		)	—
Non-cash contract asset ⁽²⁾	(52		)	(52		)	(103		)	(103		)
Deferred revenue associated with deficiency credits ⁽³⁾	213			—			213			—
Adjusted EBITDA	12,186			15,014			23,698			28,552
Add (deduct):
Cash paid for income taxes	(329		)	(267		)	(607		)	(449		)
Cash paid for interest	(2,995		)	(2,530		)	(5,815		)	(4,821		)
Maintenance capital expenditures	(45		)	(31		)	(45		)	(80		)
Distributable cash flow	$	8,817		$	12,186		$	17,231		$	23,202


⁽¹⁾	Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.


⁽²⁾	Represents the change in non-cash contract assets associated with revenue recognized in advance at blended rates based on the escalation clauses in certain of our customer contracts. Refer to Note 4. Revenues — Contract Assets of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for more information.


⁽³⁾	Represents deferred revenue associated with deficiency credits that are expected to be used in the future prior to their expiration. Amounts presented are net of the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue.

Operating Costs

Our operating costs are comprised primarily of subcontracted rail expenses, pipeline fees, repairs and maintenance expenses, materials and supplies, utility costs, insurance premiums and lease costs for facilities and equipment. In addition, our operating expenses include the cost of leasing railcars from third-party railcar suppliers and the shipping fees charged by railroads, which costs are generally passed through to our customers. We expect our expenses to remain relatively stable, but they may fluctuate from period to period depending on the mix of activities performed during a period and the timing of these expenditures. With additional throughput volumes handled at our terminals, we expect to incur additional operating costs, including subcontracted rail services and pipeline fees.

Our management seeks to maximize the profitability of our operations by effectively managing both our operating and maintenance expenses. As our terminal facilities and related equipment age, we expect to incur regular maintenance expenditures to maintain the operating capabilities of our facilities and equipment in compliance with sound business practices, our contractual relationships and regulatory requirements for operating these assets. We record these maintenance and other expenses associated with operating our assets in “Operating and maintenance” costs in our consolidated statements of income.

Volumes

The amount of Terminalling services revenue we generate depends on minimum customer commitment fees and the throughput volume that we handle at our terminals in excess of those minimum commitments. These volumes are primarily affected by the supply of and demand for crude oil, refined products and biofuels in the markets served directly or indirectly by our assets. Additionally, these volumes are affected by the spreads between the benchmark prices for these products, which are influenced by, among other things, the available takeaway capacity in those markets. Although customers at our terminals have committed to minimum monthly fees under their terminal services agreements with us, which will generate the majority of our Terminalling services revenue, our results of operations will also be affected by:


•	our customers’ utilization of our terminals in excess of their minimum monthly volume commitments;


•	our ability to identify and execute accretive acquisitions and commercialize organic expansion projects to capture incremental volumes; and


•	our ability to renew contracts with existing customers, enter into contracts with new customers, increase customer commitments and throughput volumes at our terminals, and provide additional ancillary services at those terminals.

General Trends and Outlook

We expect our business to continue to be affected by the key trends discussed in “ Item 7. Management ’ s Discussion and Analysis of Financial Condition — Factors that May Impact Future Results of Operations ” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 . To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Casper Terminal Customer Contract Renewals and Expirations

One of the existing terminalling services agreements at our Casper Terminal will expire at the end of August 2019 if not otherwise renewed or extended. If we cannot replace or extend the agreement expiring at the end of August 2019, it would have an adverse effect on our cash flows. The expiring agreement contributed approximately $9.3 million to our “Terminalling Services” revenue and approximately $6.6 million of Adjusted EBITDA during the twelve months ended June 30, 2019. We are actively engaged in discussions with this customer, and we continue to seek other opportunities to enhance the utilization and profitability of the Casper terminal with other producers, refiners and marketers of crude oil. For example, in late 2018, we executed a three-year agreement with an investment-grade rated customer at the Casper Terminal. Additionally, we have entered into a one-year terminalling service agreement, effective January 1, 2019, which contains take-or-pay terms for storage services and variable fees associated with actual throughput volumes and other services. Our ability to secure additional commercial opportunities may be limited until we successfully complete our outbound pipeline connection and Enbridge successfully completes its DRA project, both of which are not anticipated to occur until the fourth quarter or later. We cannot make any assurances regarding the success of Enbridge’s DRA project or the outcome of our efforts.

Factors Affecting the Comparability of Our Financial Results

The comparability of our current financial results in relation to prior periods are affected by the factors described below.

Income Taxes

In conjunction with our adoption of ASC 606 in the prior year, we recognized a deferred tax liability associated with the previously deferred revenues net of previously deferred pipeline fees. We recovered a portion of that deferred tax liability during the three and six months ended June 30, 2018. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 was fully recognized ratably during 2018. The deferred tax recovery of $0.9 million (representing C$1.2 million) for the three months ended June 30, 2018, and $1.8 million (representing C$2.4 million) for the six months ended June 30, 2018, was partially

offset by the Canadian tax liability attributable to our current earnings for the three and six months ended June 30, 2018. Our financial results for the three and six months ended June 30, 2019 were not affected by similar activities.

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 the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)
Operating income (loss)
Terminalling services	$	8,249		$	11,163		$	16,699		$	20,949
Fleet services	74			(4		)	5			161
Corporate and other	(3,147		)	(2,912		)	(6,122		)	(5,849		)
Total operating income	5,176			8,247			10,582			15,261
Interest expense	2,982			2,713			6,169			5,198
Loss (gain) associated with derivative instruments	1,074			(386		)	1,746			(1,410		)
Foreign currency transaction loss (gain)	20			117			202			(94		)
Other expense (income), net	21			1			(3		)	72
Provision for (benefit from) income taxes	128			(910		)	198			(1,817		)
Net income	$	951		$	6,712		$	2,270		$	13,312

Summary Analysis of Operating Results

Changes in our operating results for the three and six months ended June 30, 2019 , as compared with our operating results for the three and six months ended June 30, 2018 , were primarily driven by:

•

a decrease in operating income of our terminalling services business due to the conclusion of a contract at our Casper terminal in December 2018, increased subcontracted rail services at our Hardisty terminal and increased maintenance costs at our Stroud terminal related to our steaming equipment. The decrease in operating income was partially offset by additional revenues from two new contracts at our Stroud terminal and lower depreciation resulting from a revised estimate of the asset retirement obligation associated with our San Antonio terminal.


•	an increase in interest expense due to higher weighted average interest rates and additional amounts outstanding on our credit facility;


•	non-cash losses associated with declines in the fair value of our interest rate derivatives resulting from decreases in the interest rate index upon which the derivative values are based; and


•	an increase in our provision for income taxes for the current year due to a partial recovery of a deferred tax liability we recognized in 2018 in conjunction with our adoption of ASC 606 that we did not have in 2019, partially offset by a reduction in the Alberta provincial tax rates on business income.

A comprehensive discussion of our operating results by segment is presented below.

RESULTS OF OPERATIONS — BY SEGMENT

TERMINALLING SERVICES

The following table sets forth the operating results of our Terminalling services business and the approximate average daily throughput volumes of our terminals for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)
Revenues
Terminalling services	$	25,255		$	27,514		$	50,891		$	54,215
Freight and other reimbursables	223			548			528			763
Total revenues	25,478			28,062			51,419			54,978
Operating costs
Subcontracted rail services	3,699			3,311			7,264			6,373
Pipeline fees	4,902			5,118			9,963			10,842
Freight and other reimbursables	223			548			528			763
Operating and maintenance	1,525			1,437			3,688			2,728
Selling, general and administrative	1,597			1,225			3,260			2,787
Depreciation and amortization	5,283			5,260			10,017			10,536
Total operating costs	17,229			16,899			34,720			34,029
Operating income	8,249			11,163			16,699			20,949
Foreign currency transaction loss (gain)	(54		)	31			(95		)	62
Other expense, net	25			1			1			72
Provision for (benefit from) income taxes	123			(899		)	190			(1,834		)
Net income	$	8,155		$	12,030		$	16,603		$	22,649
Average daily terminal throughput (bpd)	117,171			92,103			100,331			87,220

Three months ended June 30, 2019 compared with three months ended June 30, 2018

Terminalling Services Revenue

Revenue generated by our Terminalling services segment decreased $2.6 million to $25.5 million for the three months ended June 30, 2019 , as compared with $28.1 million for the three months ended June 30, 2018 . This decrease was primarily due to lower revenue at our Casper terminal resulting from the conclusion of a customer agreement at the end of 2018, coupled with approximately $0.3 million of deferred revenue resulting from expected usage of deficiency credits by customers of our Hardisty terminal. Partially offsetting these decreases are higher revenues at our Stroud terminal due to rate escalations. We do not anticipate significant deferrals of revenue for our Hardisty terminal in future periods due to our expectation that all of the available capacity at the terminal will be fully utilized by our customers.

Average daily terminal throughput increased 25,068 bpd to 117,171 bpd for the three months ended June 30, 2019 , as compared with 92,103 bpd for the three months ended June 30, 2018 . Our throughput volumes increased primarily as a result of increased Western Canadian crude oil production and constrained pipeline takeaway capacity out of the region, which increased the demand for and utilization of our terminalling services by customers of our Hardisty terminal. Additionally, deliveries to our Stroud terminal increased as a result of the widening spreads between WTI and WCS, which makes delivery into the Cushing oil hub an economically favorable destination. Partially offsetting the increased utilization of our Hardisty and Stroud terminals was decreased utilization of the capacity and services at

our Casper terminal. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that primarily contain “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services. Increases in the average daily terminal throughput activity only affects revenue to the extent such amounts are in excess of the minimum monthly committed volumes. However, increases in throughput activity, or expected throughput activity, do increase the variable operating costs associated with our terminals, as discussed below.

Our terminalling services revenue for the three months ended June 30, 2019 , would have been $0.6 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended June 30, 2019 , was the same as the average exchange rate for the three months ended June 30, 2018 . The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7477 for the three months ended June 30, 2019 as compared with 0.7748 for three months ended June 30, 2018 .

Operating Costs

The operating costs of our Terminalling services segment increased $0.3 million to $17.2 million for the three months ended June 30, 2019 , as compared with the $16.9 million for the three months ended June 30, 2018 . The increase is primarily attributable to increased costs associated with the increased throughput at our Hardisty and Stroud terminals and partially offset by lower pipeline fees.

Our terminalling services operating costs for the three months ended June 30, 2019 , would have been $0.3 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended June 30, 2019 , was the same as the average exchange rate for the three months ended June 30, 2018 .

Subcontracted rail services. Our subcontracted rail services costs increased $0.4 million to $3.7 million for the three months ended June 30, 2019 as compared with $3.3 million for the three months ended June 30, 2018 . This increase was primarily due to the increase in the throughput at our Hardisty and Stroud terminals partially offset by a decrease at our Casper terminal resulting from the conclusion of a customer agreement at the end of 2018.

Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating costs. Our pipeline fees decreased $0.2 million to $4.9 million for the three months ended June 30, 2019 as compared with $5.1 million for the three months ended June 30, 2018 , primarily due to higher direct operating costs at our Hardisty terminal, which reduce the amounts we pay to Gibson. Additionally, we deferred approximately $0.1 million of pipeline fees associated with revenue we deferred for the expected usage of deficiency credits in future periods.

Selling, general and administrative. Our selling, general and administrative costs increased $0.4 million to $1.6 million for the three months ended June 30, 2019 as compared with $1.2 million for the three months ended June 30, 2018 . This increase was primarily due to higher compliance consulting and legal costs at our Casper terminal.

Other Expenses

Provision for (benefit from) income taxes . A significant amount of our operating income is generated by our Hardisty terminal located in the Canadian province of Alberta. As a Canadian business, operating income derived from our Hardisty terminal is subject to corporate income taxes assessed at rates enacted by the Canadian federal and provincial governments which currently total 26.5% on a combined basis. In late June 2019, the Alberta Provincial Government enacted legislation to reduce the provincial tax on business income from the previous rate of 12% to a rate of 8% in 2022. The provincial tax on business income was reduced to 11% effective July 1, 2019, which resulted in a blended rate of 11.5% for 2019 . The provincial tax on business income is further reduced each year by 1% until the tax rate reaches 8% beginning January 1, 2022. While the provincial tax on business income will reduce our income tax expense in future periods, we do not anticipate these reductions to significantly affect our operating results or cash flows.

Our income taxes for the Terminalling services segment increased $1.0 million to a provision of $0.1 million for the three months ended June 30, 2019 , from a $0.9 million benefit from income taxes for the three months ended

June 30, 2018 . In connection with our adoption of ASC 606, in 2018, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the three months ended June 30, 2018 , we recovered $0.9 million (C$1.2 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We did not have a similar recovery of a deferred tax liability during the three months ended June 30, 2019.

Six months ended June 30, 2019 compared with six months ended June 30, 2018

Terminalling Services Revenue

Revenue generated by our Terminalling services segment decreased $3.6 million to $51.4 million for the six months ended June 30, 2019 , as compared with $55.0 million for the six months ended June 30, 2018 . This decrease was primarily due to lower revenue at our Casper terminal resulting from the conclusion of a customer agreement at the end of 2018, partially offset by additional contracts that we have executed and our commercial efforts to market the available capacity. The lower revenue at our Casper terminal was also partially offset by higher revenues at our Stroud terminal associated with additional contracts that were executed in March and April of 2018.

Our average daily terminal throughput increased 13,111 bpd to 100,331 bpd for the six months ended June 30, 2019 as compared with the six months ended June 30, 2018 . Our throughput volumes increased primarily due to increased activity by customers of our Hardisty and Stroud terminals offset by a decrease at our Casper terminal. The increased activity associated with our Hardisty terminal resulted from increased Western Canadian crude oil production and constrained pipeline takeaway capacity out of the region during the first half of 2019. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that contain primarily “take-or-pay” provisions, where we are entitled to the payment of minimum monthly commitment fees from our customers, which are recognized as revenue as we provide terminalling services. Increases in the average daily terminal throughput activity only affects revenue to the extent such amounts are in excess of the minimum monthly committed volumes. Increases in the average daily terminal throughput activity only affect revenue to the extent such amounts are in excess of the minimum monthly committed volumes. However, increases in throughput activity, or expected throughput activity, result in increases to the variable operating costs associated with our terminals, as discussed below.

Our terminalling services revenue for the six months ended June 30, 2019 , would have been $1.4 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the six months ended June 30, 2019 , was the same as the average exchange rate for the six months ended June 30, 2018 . The average exchange rate for the Canadian dollar in relation to the U.S. dollar was 0.7499 for the six months ended June 30, 2019 as compared with 0.7829 for the six months ended June 30, 2018 .

Operating Costs

The operating costs of our Terminalling services segment increased $0.7 million to $34.7 million for the six months ended June 30, 2019 , as compared with the $34.0 million for the six months ended June 30, 2018 . The increase is attributable to additional variable operating costs at our Hardisty and Stroud terminals associated with subcontracted rail service costs resulting from higher throughput volumes. We also incurred increased operating costs at our Stroud terminal in connection with the steaming equipment we installed for alleviating unloading issues due to cold weather. These costs were partially offset by a decrease in pipeline fees and depreciation expense as discussed in more detail below.

Our terminalling services operating costs for the six months ended June 30, 2019 , would have been $0.8 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the six months ended June 30, 2019 , was the same as the average exchange rate for the six months ended June 30, 2018 .

Subcontracted rail services. Our subcontracted rail services costs increased $0.9 million to $7.3 million for the six months ended June 30, 2019 , as compared with $6.4 million for the six months ended June 30, 2018 . This increase was primarily due to the increased throughput at our Stroud terminal associated with the additional contracts that were executed in March and April of 2018 and increased throughput at our Hardisty terminal, offset by a reduction at our Casper terminal resulting from the conclusion of a customer agreement at the end of 2018.

Pipeline fees. We incur pipeline fees related to a facilities connection agreement with Gibson for the delivery of crude oil from Gibson’s Hardisty storage terminal to our Hardisty terminal via pipeline. The pipeline fees we pay to Gibson are based on a predetermined formula, which includes amounts collected from customers at our Hardisty terminal less direct operating costs. Our pipeline fees decreased $0.9 million to $10.0 million for the six months ended June 30, 2019 as compared with the six months ended June 30, 2018 , primarily due to lower revenue and higher direct operating costs at our Hardisty terminal, which reduce the amounts we pay to Gibson.

Operating and maintenance . Operating and maintenance expense increased $1.0 million to $3.7 million for the six months ended June 30, 2019 from $2.7 million for the six months ended June 30, 2018 . The increased operating and maintenance expenses are primarily due to costs incurred for the steaming equipment at our Stroud terminal, which was placed into service in July 2018 to alleviate unloading issues related to cold weather at the terminal. Additionally, we incurred higher repairs and maintenance expenses at our Hardisty and Stroud terminals.

Selling, general and administrative. Our selling, general and administrative costs increased $0.5 million to $3.3 million for the six months ended June 30, 2019 , as compared with $2.8 million for the six months ended June 30, 2018 . This increase was primarily due to higher compliance consulting and legal costs at our Casper terminal.

Depreciation and amortization . Depreciation and amortization expense decreased $0.5 million to $10.0 million for the six months ended June 30, 2019 from $10.5 million for the six months ended June 30, 2018 . The decrease is due to a revised estimate of our asset retirement obligations, or ARO, associated with our San Antonio facility that we recorded during the first quarter of 2019.

Other Expenses

Our income taxes for the Terminalling services segment increased $2.0 million to a provision of $0.2 million for the six months ended June 30, 2019 , from a benefit of $1.8 million from income taxes for the six months ended June 30, 2018 . In connection with our adoption of ASC 606, in 2018, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the six months ended June 30, 2018 , we recovered $1.8 million (C$2.4 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We did not have a similar recovery of a deferred tax liability during the six months ended June 30, 2019 .

FLEET SERVICES

The following table sets forth the operating results of our Fleet services segment for the periods indicated:



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
	(in thousands)
Revenues
Fleet leases	$	983	$	983		$	1,967		$	1,967
Fleet services	279		309			563			880
Freight and other reimbursables	75		223			234			1,485
Total revenues	1,337		1,515			2,764			4,332
Operating costs
Freight and other reimbursables	75		223			234			1,485
Operating and maintenance	985		1,061			2,033			2,126
Selling, general and administrative	203		235			492			560
Total operating costs	1,263		1,519			2,759			4,171
Operating income (loss)	74		(4		)	5			161
Foreign currency transaction loss (gain)	4		(3		)	8			(7		)
Provision for (benefit from) income taxes	5		(12		)	8			16
Net income (loss)	$	65	$	11		$	(11	)	$	152

Three Months Ended June 30, 2019 compared with three months ended June 30, 2018

Revenues from our Fleet services segment decreased to $1.3 million for the three months ended June 30, 2019 , as compared with revenue of $1.5 million for the three months ended June 30, 2018 . The decrease in revenue was primarily attributable to fewer customer reimbursements to us for freight and other reimbursable charges that we have incurred on their behalf. The decrease in Freight and other reimbursables revenue was exactly offset by a corresponding decrease in Freight and other reimbursables operating costs that primarily arose from railcar repairs and returns, which occurred during the second quarter of 2018. We did not incur similar costs during the second quarter of 2019 as we had no returns of railcars during this period. Additionally, fleet services revenues decreased over the prior year associated with approximately 800 fewer railcars outstanding for which we provided fleet services, as compared with the same period in 2018.

Historically we have assisted our customers with procuring railcars to facilitate their use of our terminalling services. Our wholly-owned subsidiary USD Rail LP has historically entered into leases with third-party manufacturers of railcars and financial firms, which were then leased to customers. Although we expect to continue assisting our customers with obtaining railcars for their use transporting crude oil from our terminals, as our existing lease agreements expire, or are otherwise terminated, we do not expect to enter into similar leasing arrangements in the future. Should market conditions change, we would potentially assist with the procurement and management of railcars on behalf of our customers again in the future.

Six months ended June 30, 2019 compared with six months ended June 30, 2018

The results for our Fleet services segment for the six months ended June 30, 2019 , compared to the same period in 2018 , changed for the same reasons as noted in the three month analysis above.

CORPORATE ACTIVITIES

The following table sets forth our corporate charges for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)
Operating costs
Selling, general and administrative	$	3,147		$	2,912		$	6,122		$	5,849
Operating loss	(3,147		)	(2,912		)	(6,122		)	(5,849		)
Interest expense	2,982			2,713			6,169			5,198
Loss (gain) associated with derivative instruments	1,074			(386		)	1,746			(1,410		)
Foreign currency transaction loss (gain)	70			89			289			(149		)
Other income, net	(4		)	—			(4		)	—
Provision for income taxes	—			1			—			1
Net loss	$	(7,269	)	$	(5,329	)	$	(14,322	)	$	(9,489	)

Three months ended June 30, 2019 compared with three months ended June 30, 2018

Costs associated with our corporate activities increased $1.9 million to $7.3 million for the three months ended June 30, 2019 . Our “Interest expense” increased $0.3 million to $3.0 million , due to an increase in the interest rates we were charged under our Credit Agreement, as well as a higher weighted average balance of debt outstanding during the three months ended June 30, 2019 , as compared with the same period of 2018 . Also contributing to the increase in costs associated with our corporate activities during the three months ended June 30, 2019 was a non-cash loss of $1.1 million associated with our interest rate derivatives as compared with a non-cash gain of $0.4 million for the corresponding period in 2018.

Six months ended June 30, 2019 compared with six months ended June 30, 2018

Costs associated with our corporate activities increased $4.8 million to $14.3 million for the six months ended June 30, 2019 , for the same reasons cited above in our three month analysis.

LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements include:


•	financing current operations;


•	servicing our debt;


•	funding capital expenditures, including acquisitions and the costs to construct new assets; and


•	making distributions to our unitholders.

We have historically financed our operations with cash generated from our operating activities, borrowings under our Revolving Credit Facility, issuances of partnership interests and loans from our sponsor.

Liquidity Sources

We expect our ongoing sources of liquidity to include borrowings under our $385 million senior secured credit agreement, issuances of debt securities and additional partnership interests, as well as cash generated from our operating activities. We believe that cash generated from these sources will be sufficient to meet our ongoing working capital and capital expenditure requirements and to make quarterly cash distributions.

For information regarding our Credit Agreement, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreement in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and Part I. Item 1. Financial Statements, Note 10. Debt of this Quarterly Report.

The following table presents our available liquidity as of the dates indicated:



	June 30, 2019		December 31, 2018
	(in millions)
Cash and cash equivalents ⁽¹⁾	$	7.2	$	6.4
Aggregate borrowing capacity under Credit Agreement	385.0		385.0
Less: Revolving Credit Facility amounts outstanding	216.0		209.0
Letters of credit outstanding	0.6		0.6
Total available liquidity ⁽²⁾	$	175.6	$	181.8


⁽¹⁾	Excludes amounts that are restricted pursuant to our collaborative agreement with Gibson.


⁽²⁾	Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA, which equates to approximately $34 million of availability at June 30, 2019 .

Energy Capital Partners must approve any additional issuances of equity by us, and such determinations may be made free of any duty to us or our unitholders. Members of our general partner’s board of directors appointed by Energy Capital Partners must also approve the incurrence by us of additional indebtedness or refinancing outside of our existing indebtedness that are not in the ordinary course of business.

Cash Flows

The following table and discussion summarizes the cash flows associated with our operating, investing and financing activities for the periods indicated:



	Six Months Ended June 30,
	2019			2018
	(in thousands)
Net cash provided by (used in):
Operating activities	$	19,507		$	19,588
Investing activities	(2,677		)	34
Financing activities	(15,358		)	(17,939		)
Effect of exchange rates on cash	605			(853		)
Net change in cash, cash equivalents and restricted cash	$	2,077		$	830

Operating Activities

Net cash provided by operating activities decreased $0.1 million to $19.5 million for the six months ended June 30, 2019 , from $19.6 million for the six months ended June 30, 2018 . The decrease in Net cash provided by operating activities, was primarily due to the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities increased to $2.7 million for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily due to the pipeline construction at the Casper terminal.

Financing Activities

Net cash used in financing activities decreased to $15.4 million for the six months ended June 30, 2019 from $17.9 million for the six months ended June 30, 2018 . Our net borrowings of long-term debt during the six months ended June 30, 2019 were $4.0 million higher than the net amounts we borrowed during the six months ended June 30, 2018 . Partially offsetting the cash provided from our net borrowing activities, are increases in cash we used during the six months ended June 30, 2019 , for cash distributions and participant withholding taxes associated with vested Phantom Units, both of which exceeded amounts paid during the six months ended June 30, 2018 , for similar items.

Cash Requirements

Our primary requirements for cash are: (1) financing current operations, (2) servicing our debt, (3) funding capital expenditures, including acquisitions and the costs to construct new assets, and (4) making distributions to our unitholders.

Capital Requirements

Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing facilities and to meet environmental and operational regulations.

Our partnership agreement requires that we categorize our capital expenditures as either expansion capital expenditures, maintenance capital expenditures, or investment capital expenditures. Although we have not experienced significant maintenance capital expenditures in prior years as the age of our assets increase, we expect that costs we incur to maintain our assets in compliance with sound business practice, our contractual relationships and applicable regulatory requirements will likely increase. Some of these costs will be characterized as maintenance capital expenditures. We incurred $45 thousand for maintenance capital expenditures during the three and six months ended June 30, 2019 .

Our total expansion capital expenditures for the six months ended June 30, 2019 were $2.6 million . We expect to fund future capital expenditures, including the remaining $4.2 million of capital expenditures related to the construction of the outbound pipeline connection from the Casper Terminal to a nearby terminal, which is expected to be complete in late November 2019, from cash on our balance sheet, cash flow generated from our operating activities, borrowings under our Credit Agreement and the issuance of additional partnership interests or long-term debt.

Debt Service

We anticipate reducing our outstanding indebtedness to the extent we generate cash flows in excess of our operating, investing and distribution needs. During the six months ended June 30, 2019 , we received proceeds from borrowings of $20.0 million on our Revolving Credit Facility which we used for general partnership purposes and made repayments of $13.0 million on our Revolving Credit Facility from cash flow in excess of our operating and investing needs.

Distributions

We intend to pay a minimum quarterly distribution of at least $0.2875 per unit per quarter. Our current quarterly distribution of $0.365 per unit that we expect to pay, equates to $10.0 million per quarter, or $40.0 million per year, based on the number of common, subordinated, and general partner units outstanding as of August 6, 2019 . We do not have a legal obligation to distribute any particular amount per common unit. Additionally, members of our general partner’s board of directors appointed by Energy Capital Partners, if any, must approve any distributions made by us.

Other Items Affecting Liquidity

Credit Risk

Our exposure to credit risk may be affected by the concentration of our customers within the energy industry, as well as changes in economic or other conditions. Our customers’ businesses react differently to changing conditions. We believe that our credit-review procedures, customer deposits and collection procedures have adequately provided for amounts that may become uncollectible in the future.

Foreign Currency Exchange Risk

We currently derive a significant portion of our cash flow from our Canadian operations, particularly our Hardisty terminal. As a result, portions of our cash and cash equivalents are denominated in Canadian dollars and are held by foreign subsidiaries, which amounts are subject to fluctuations resulting from changes in the exchange rate between the U.S. dollar and the Canadian dollar. We routinely employ derivative financial instruments to minimize our exposure to the effect of foreign currency fluctuations, as we deem necessary based upon anticipated economic conditions.

SUBSEQUENT EVENTS

Refer to Note 21. Subsequent events of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report for a discussion regarding subsequent events.

RECENT ACCOUNTING PRONOUNCEMENTS — NOT YET ADOPTED

Refer to Note 2. Recent Accounting Pronouncements of our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this report for a discussion regarding recent accounting pronouncements that we have not yet adopted.

OFF BALANCE SHEET ARRANGEMENTS

In the normal course of business, we are a party to off-balance sheet arrangements relating to various master fleet services agreements, whereby we have agreed to assign certain payment and other obligations to third party special purpose entities that are not consolidated with us. We have also entered into agreements to provide fleet services to these special purpose entities for fixed servicing fees and reimbursement of out-of-pocket expenses. The purpose of these transactions is to remove the risk to us of non-payment by our customers, which would otherwise negatively

impact our financial condition and results of operations. For more information on these special purpose entities, see the discussion of our relationship with the variable interest entities described in Note 12. Nonconsolidated Variable Interest Entities to our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report. Assets and liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

As a smaller reporting company, we are not required to provide the information required by this Item.


Item 4.	Controls and Procedures.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, or 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 June 30, 2019 . 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 for timely decisions regarding required disclosure and to ensure information 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 June 30, 2019 , at the reasonable assurance level.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

We did not make any changes in our internal control over financial reporting during the three months ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. We do not believe that we are currently a party to any litigation that will have a material adverse impact on our financial condition, results of operations or statements of cash flows. We are not aware of any material legal or governmental proceedings against us, or any proceedings known to be contemplated by governmental authorities.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the ordinary course of our business. Risk factors relating to us are set forth under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 . No material changes to such risk factors have occurred during the three and six months ended June 30, 2019 .

Item 6. Exhibits

The following “Index of Exhibits” is hereby incorporated into this Item.



		Index of Exhibits
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).

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 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Schema Document

101.CAL*		XBRL Calculation Linkbase Document

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document


*	Filed herewith.


**	Furnished herewith.

SIGNATURES

Pursuant to the requirements 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 P ARTNERS LP (Registrant)

		By:	USD Partners GP LLC, its General Partner

Date:	August 6, 2019	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	August 6, 2019	By:	/s/ Adam Altsuler
			Adam Altsuler Senior Vice President and Chief Financial Officer (Principal Financial Officer)

TABLE OF CONTENTS

Part I Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Exhibits

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). 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 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2** Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

USDP 10-Q Quarter ended June 30, 2019

Exhibits