USD Partners LP - Quarter Report: 2018 September (Form 10-Q)

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 September 30, 2018



¨	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

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 November 2, 2018, there were 21,915,642 common units, 4,185,418 subordinated units, 38,750 Class A 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	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 4.	Controls and Procedures	63
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	64
Item 1A.	Risk Factors	64
Item 6.	Exhibits	64
SIGNATURES		66

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) our limited history as a separate public partnership; (6) the price and availability of debt and equity financing; (7) hazards and operating risks that may not be covered fully by insurance; (8) disruptions due to equipment interruption or failure at our facilities or third-party facilities on which our business is dependent; (9) natural disasters, weather-related delays, casualty losses and other matters beyond our control; (10) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations, that may increase our costs; and (11) our ability to successfully identify and finance acquisitions and other growth opportunities. 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, 2017, which is available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or SEC, website (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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(unaudited; in thousands, except per unit amounts)
Revenues
Terminalling services	$	21,728		$	19,805		$	65,560		$	65,463
Terminalling services — related party	5,715			4,737			15,414			9,091
Fleet leases	—			643			—			1,929
Fleet leases — related party	984			1,013			2,951			2,794
Fleet services	80			470			505			1,405
Fleet services — related party	227			218			682			776
Freight and other reimbursables	852			118			3,780			483
Freight and other reimbursables — related party	—			—			4			1
Total revenues	29,586			27,004			88,896			81,942
Operating costs
Subcontracted rail services	3,674			2,340			10,047			6,148
Pipeline fees	5,267			5,973			16,109			16,802
Fleet leases	984			1,656			2,961			4,723
Freight and other reimbursables	852			118			3,784			484
Operating and maintenance	1,360			749			3,553			2,050
Selling, general and administrative	2,463			2,221			7,912			6,898
Selling, general and administrative — related party	1,893			1,477			5,640			4,305
Depreciation and amortization	5,271			5,254			15,807			15,164
Total operating costs	21,764			19,788			65,813			56,574
Operating income	7,822			7,216			23,083			25,368
Interest expense	2,827			2,388			8,025			7,508
Loss (gain) associated with derivative instruments	(413		)	667			(1,823		)	1,279
Foreign currency transaction gain	(89		)	(457		)	(183		)	(527		)
Other expense (income), net	(1		)	(52		)	71			(65		)
Income before income taxes	5,498			4,670			16,993			17,173
Benefit from income taxes	(430		)	(605		)	(2,247		)	(1,806		)
Net income	$	5,928		$	5,275		$	19,240		$	18,979
Net income attributable to limited partner interests	$	5,719		$	5,127		$	18,616		$	18,517
Net income per common unit (basic and diluted)	$	0.21		$	0.20		$	0.72		$	0.77
Weighted average common units outstanding	21,915			19,538			21,480			17,380
Net income per subordinated unit (basic and diluted)	$	0.21		$	0.19		$	0.71		$	0.76
Weighted average subordinated units outstanding	4,185			6,278			4,569			6,661

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018			2017
	(unaudited; in thousands)
Net income	$	5,928	$	5,275	$	19,240		$	18,979
Other comprehensive income (loss) — foreign currency translation	997		2,105		(1,791		)	4,021
Comprehensive income	$	6,925	$	7,380	$	17,449		$	23,000

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2018			2017
	(unaudited; in thousands)
Cash flows from operating activities:
Net income	$	19,240		$	18,979
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,807			15,164
Loss (gain) associated with derivative instruments	(1,823		)	1,279
Settlement of derivative contracts	(38		)	242
Unit based compensation expense	4,333			2,962
Deferred income taxes	(3,269		)	(293		)
Other	719			664
Changes in operating assets and liabilities:
Accounts receivable	(3,459		)	267
Accounts receivable — related party	2,450			(224		)
Prepaid expenses and other assets	372			1,469
Other assets — related party	59			—
Accounts payable and accrued expenses	272			990
Accounts payable and accrued expenses — related party	(2,061		)	(43		)
Deferred revenue and other liabilities	(403		)	(4,861		)
Deferred revenue — related party	17			948
Net cash provided by operating activities	32,216			37,543
Cash flows from investing activities:
Additions of property and equipment	(443		)	(26,708		)
Proceeds from the sale of assets	236			—
Net cash used in investing activities	(207		)	(26,708		)
Cash flows from financing activities:
Distributions	(29,573		)	(25,532		)
Vested phantom units used for payment of participant taxes	(1,350		)	(1,072		)
Net proceeds from issuance of common units	—			33,700
Proceeds from long-term debt	20,000			44,000
Repayments of long-term debt	(21,000		)	(66,342		)
Net cash used in financing activities	(31,923		)	(15,246		)
Effect of exchange rates on cash	(679		)	242
Net change in cash, cash equivalents and restricted cash	(593		)	(4,169		)
Cash, cash equivalents and restricted cash — beginning of period	13,788			17,138
Cash, cash equivalents and restricted cash — end of period	$	13,195		$	12,969

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	September 30, 2018			December 31, 2017
	(unaudited; in thousands, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	7,361		$	7,874
Restricted cash	5,834			5,914
Accounts receivable, net	7,601			4,171
Accounts receivable — related party	903			410
Prepaid expenses	1,848			2,545
Other current assets	172			43
Other current assets — related party	79			79
Total current assets	23,798			21,036
Property and equipment, net	142,117			146,573
Intangible assets, net	89,857			99,312
Goodwill	33,589			33,589
Other non-current assets	2,364			328
Other non-current assets — related party	114			174
Total assets	$	291,839		$	301,012

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	2,995		$	2,670
Accounts payable and accrued expenses — related party	795			244
Deferred revenue	3,071			3,291
Deferred revenue — related party	1,968			1,986
Other current liabilities	2,491			2,339
Total current liabilities	11,320			10,530
Long-term debt, net	200,247			200,627
Deferred income tax liabilities, net	1,107			4,490
Other non-current liabilities	386			475
Total liabilities	213,060			216,122
Commitments and contingencies
Partners’ capital
Common units (21,915,359 and 19,537,971 outstanding at September 30, 2018 and December 31, 2017, respectively)	112,782			136,645
Class A units (38,750 and 82,500 outstanding at September 30, 2018 and December 31, 2017, respectively)	987			1,468
Subordinated units (4,185,418 and 6,278,127 outstanding at September 30, 2018 and December 31, 2017, respectively)	(38,436		)	(55,237		)
General partner units (461,136 outstanding at September 30, 2018 and December 31, 2017)	3,403			180
Accumulated other comprehensive income	43			1,834
Total partners’ capital	78,779			84,890
Total liabilities and partners’ capital	$	291,839		$	301,012

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Nine Months Ended September 30,
	2018					2017
	Units		Amount			Units		Amount
	(unaudited; in thousands, except unit amounts)
Common units
Beginning balance	19,537,971		$	136,645		14,185,599		$	128,903
Conversion of units	2,131,459		(18,245		)	2,162,084		(19,047		)
Common units issued for vested phantom units	245,929		(1,350		)	190,016		(1,072		)
Issuance of common units	—		—			3,000,000		33,700
Net income	—		15,337			—		13,421
Unit based compensation expense	—		3,753			—		2,677
Distributions	—		(23,358		)	—		(17,594		)
Ending balance	21,915,359		112,782			19,537,699		140,988
Class A units
Beginning balance	82,500		1,468			138,750		1,929
Conversion of units	(38,750	)	(674		)	(46,250	)	(606		)
Net income	—		33			—		75
Unit based compensation expense	—		144			—		356
Forfeited units	(5,000	)	73			(10,000	)	(247		)
Distributions	—		(57		)	—		(109		)
Ending balance	38,750		987			82,500		1,398
Subordinated units
Beginning balance	6,278,127		(55,237		)	8,370,836		(70,936		)
Conversion of units	(2,092,709	)	18,919			(2,092,709	)	19,653
Net income	—		3,246			—		5,021
Unit based compensation expense	—		26			—		23
Distributions	—		(5,390		)	—		(7,294		)
Ending balance	4,185,418		(38,436		)	6,278,127		(53,533		)
General Partner units
Beginning balance	461,136		180			461,136		356
Capital contribution	—		3,366			—		—
Net income	—		624			—		462
Unit based compensation expense	—		1			—		1
Distributions	—		(768		)	—		(535		)
Ending balance	461,136		3,403			461,136		284
Accumulated other comprehensive income (loss)
Beginning balance			1,834					(1,726		)
Cumulative translation adjustment			(1,791		)			4,021
Ending balance			43					2,295
Total partners’ capital at September 30,			$	78,779				$	91,432

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. Our common units are traded on the New York Stock Exchange, or NYSE, under the symbol USDP.

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 September 30, 2018, our results of operations for the three and nine months ended September 30, 2018 and 2017, and our cash flows for the nine months ended September 30, 2018 and 2017. We derived our consolidated balance sheet as of December 31, 2017 from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Our results of operations for the three and nine months ended September 30, 2018 and 2017 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, 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, 2017.

Effective January 1, 2018, we adopted the requirements of Accounting Standards Update 2014-09, or ASU 2014-09, Revenue from Contracts with Customers, or ASC 606, and Accounting Standards Update 2016-18, or ASU 2016-18, Statement of Cash Flows, Restricted Cash, as discussed in Note 2. Recent Accounting Pronouncements. All amounts and disclosures set forth in this Form 10-Q have been updated to comply with the new standards.

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.

2. RECENT ACCOUNTING PROUNOUNCEMENTS

Recently Adopted Accounting Pronouncements

ASU No. 2016-18

In November 2016, the Financial Accounting Standards Board, or FASB, issued ASU No. 2016-18, which amends the FASB Accounting Standards Codification, or ASC, Topic 230 to require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when we reconcile the beginning-of-period and end-of-period total amounts shown on our consolidated statements of cash flows.

We adopted the provisions of ASU 2016-18 retrospectively on January 1, 2018. As a result of including restricted cash with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts presented on the consolidated statements of cash flows, net cash flows for the nine months ended September 30, 2017 increased by $5.1 million.

ASU No. 2014-09

In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers, or ASC 606, which provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most previously required revenue recognition guidance, including industry-specific guidance. We adopted the provisions of ASC 606 using the full retrospective method on January 1, 2018. We applied the standard’s right-to-invoice practical expedient on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

We revised our consolidated financial statements from amounts previously reported due to our adoption of ASC 606 as presented in the following discussion and tables:

Terminalling Services Revenue and Deferred Revenue — Terminalling services revenue decreased by $2.0 million and $1.8 million for the three and nine months ended September 30, 2017, respectively, due to our adoption of ASC 606. The changes to our Terminalling services revenue represent the recognition of previously deferred revenue in connection with payments we receive from customers of our Hardisty terminal for their minimum monthly volume commitments for the respective periods in connection with our adoption of ASC 606. We have historically deferred recognition of all such amounts due to the make-up rights we have granted customers of our Hardisty terminal for periods up to six months following the month for which the minimum volume commitments were paid. Historically, breakage associated with these make-up rights options has approximated 100%. Breakage rates are regularly evaluated and modified as necessary to reflect our current expectations and experience. The balance of our deferred revenue at December 31, 2017, decreased by $21.9 million due to our adoption of ASC 606.

Pipeline Fees and Prepaid Expenses — Our “Pipeline fees” expense decreased by $0.4 million for both the three and nine months ended September 30, 2017. We have historically recorded amounts paid to Gibson Energy Partnership,

or Gibson, for pipeline fees as a prepaid expense, which we have recognized as expense concurrently with our recognition of revenue associated with the expiration of the make-up rights we granted to customers of our Hardisty terminal. As a result of our recognition of a portion of the previously deferred revenue, we concurrently recognized a proportionate amount of the prepaid pipeline fees as expense in connection with our adoption of ASC 606. The balance of prepaid expenses at December 31, 2017, decreased by $6.4 million due to our adoption of ASC 606.

Provision for Income Taxes and Non-current Deferred Income Tax Liability — Our benefit from income taxes increased by $0.4 million for both the three and nine months ended September 30, 2017. The change in our benefit for income taxes is attributable to the lower income resulting from changes in “Pipeline fees” and “Terminalling services revenue” associated with our adoption of ASC 606 as discussed above, which affected our benefit for income taxes and the related non-current deferred income tax liability. The balance of our deferred income tax liability at December 31, 2017, increased by $3.9 million due to our adoption of ASC 606.

Other Comprehensive Income (Loss) — Foreign Currency Translation and Accumulated Other Comprehensive Income (Loss) — Our translation of the foregoing items within the consolidated income statements and balance sheets of our Canadian subsidiaries resulted in changes to the amounts reported in our consolidated statements of comprehensive income for “Other comprehensive income (loss) — foreign currency translation” and the related amount for “Accumulated other comprehensive income” included in our consolidated balance sheets. The functional currency of our Hardisty terminal is the Canadian dollar, which we translate into U.S. dollars for reporting in our consolidated financial statements. We had an increase of $0.4 million and $0.9 million in our “Other comprehensive income (loss) — foreign currency translation” for the three and nine months ended September 30, 2017, respectively. The balance of “Accumulated other comprehensive income” at December 31, 2017, increased by $0.2 million due to our adoption of ASC 606.

Cash Flows From Operating Activities — Our adoption of ASC 606 did not affect the amount we reported as Cash flows from operating activities, as our adoption of this standard did not affect our cash flow. However, the components that comprise “Net cash provided by operating activities” within our consolidated statements of cash flows changed to reflect the revised amounts presented in our consolidated statements of income and consolidated balance sheets as discussed above.

The following tables show the adjustments for our adoption of ASC 606 and the resulting balances for each affected line item in our consolidated statements of income for the period indicated:



	Three months ended September 30, 2017
	As reported			Adjustments			As adjusted
	(in thousands)
Revenues	$	28,981		$	(1,977	)	$	27,004
Operating costs	20,182			(394		)	19,788
Operating income	8,799			(1,583		)	7,216
Other income, net	(48		)	(4		)	(52		)
Income before income taxes	6,249			(1,579		)	4,670
Benefit from income taxes	(178		)	(427		)	(605		)
Net income	6,427			(1,152		)	5,275



	Nine months ended September 30, 2017
	As reported			Adjustments			As adjusted
	(in thousands)
Revenues	$	83,722		$	(1,780	)	$	81,942
Operating costs	56,925			(351		)	56,574
Operating income	26,797			(1,429		)	25,368
Other income, net	(40		)	(25		)	(65		)
Income before income taxes	18,577			(1,404		)	17,173
Benefit from income taxes	(1,427		)	(379		)	(1,806		)
Net income	20,004			(1,025		)	18,979

The following table shows the adjustments for our adoption of ASC 606 and ASU 2016-18 and the resulting balance for each affected line item in our consolidated statements of cash flow for the period indicated:



	Nine months ended September 30, 2017
	As reported			Adjustments			As adjusted
	(in thousands)
Net income	$	20,004		$	(1,025	)	$	18,979
Deferred income taxes	86			(379		)	(293		)
Prepaid expenses and other assets	1,819			(350		)	1,469
Deferred revenue and other liabilities	(6,733		)	1,872			(4,861		)
Deferred revenue — related party	1,066			(118		)	948
Net cash provided by operating activities	38,228			(685		)	37,543
Effect of exchange rates on cash	(148		)	390			242
Net change in cash, cash equivalents and restricted cash	(3,874		)	(295		)	(4,169		)
Cash, cash equivalents and restricted cash — beginning of period	11,705			5,433			17,138
Cash, cash equivalents and restricted cash — end of period	7,831			5,138			12,969

The following table shows the adjustments for our adoption of ASC 606 and the resulting balance for each affected line item in our consolidated balance sheet for the period indicated:



	December 31, 2017
	As reported		Adjustments			As adjusted
	(in thousands)
Assets:
Accounts receivable, net	$	4,137	$	34		$	4,171
Prepaid expenses	8,957		(6,412		)	2,545
Liabilities:
Deferred revenue	22,011		(18,720		)	3,291
Deferred revenue — related party	5,115		(3,129		)	1,986
Deferred income tax liabilities, net	614		3,876			4,490

The cumulative effect of the change on our partners’ capital accounts at January 1, 2017 was as follows:



Partners’ Capital Account	Amount As reported			Cumulative Effect			Retrospectively Adjusted Amount
	(in thousands)
Common units	$	122,802		$	6,101		$	128,903
Class A units	1,811			118			1,929
Subordinated units	(76,749		)	5,813			(70,936		)
General partner	111			245			356
Accumulated other comprehensive loss	(1,157		)	(569		)	(1,726		)
Total partners’ capital	$	46,818		$	11,708		$	58,526

Please refer to Note 4. Revenues for additional information regarding our adoption of ASC 606.

Recent Accounting Pronouncements Not Yet Adopted

Compensation — Stock Compensation

In June 2018, the FASB issued Accounting Standards Update No. 2018-07, or ASU 2018-07, which amends ASC Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The amendment specifies 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. The provisions of this standard will affect the manner in which we value the phantom units we grant to our directors and consultants domiciled in the United States, but it is not expected to have a material impact on our operating results, cash flows or financial position.

This pronouncement is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Although early adoption of ASU 2018-07 is permitted, we do not expect to early adopt the provisions of this standard.

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.

Leases

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, or ASU 2016-02, which amends ASC Topic 842 to require balance sheet recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The amendment provides an option that permits us to elect not to recognize the lease assets and liabilities for leases with a term of 12 months or less. The pronouncement is effective for years beginning after December 15, 2018, and early adoption is permitted. In July 2018, the FASB issued ASU 2018-11 providing

another transition method in addition to the existing transition method by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, or prospectively. Additionally, the FASB has issued and is likely to continue issuing Accounting Standards Updates to clarify application of the guidance in the original standard and to provide practical expedients for implementing the standard, all of which will be effective upon adoption.

We continue to assess the impact our adoption of ASU 2016-02 will have on our consolidated financial statements, but we currently cannot reasonably estimate the effect. We do not currently recognize operating leases in our balance sheets as will be required by ASU 2016-02, but we record payments for operating leases as rent expense as incurred. Our process for implementing ASU 2016-02 involves evaluating all of our existing leases with terms greater than 12 months to quantify the impact to our financial statements, developing accounting policies and internal control processes to address adherence to the requirements of the standard, evaluating the capability of existing accounting systems and any enhancements needed, determining the need to modify any bank or debt compliance requirements, and training and educating our workforce and the investment community regarding the financial statement impact that application of the standard will have. We have completed steps to identify, accumulate and categorize our lease agreements into homogeneous groups to evaluate the particular terms and conditions for each type of agreement in relation to the requirements of ASU 2016-02 and are evaluating the accounting impact, commonly referred to as an “Impact Assessment.” We have also progressed with the development of accounting policies and internal control processes for lease items identified in the performance of our impact assessment. Additionally, we are developing resources to facilitate management of the information necessary to properly account for and report new and existing leases pursuant to the provisions of ASC 842. We will adopt the provisions of this standard on January 1, 2019, prospectively, pursuant to the provisions of ASU 2018-11.

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.

Our computation of net income per limited partner unit excludes the effects of 1,239,488 phantom unit awards outstanding for the three and nine months ended September 30, 2018 and 1,135,223 phantom unit awards outstanding for the three and nine months ended September 30, 2017, as they were anti-dilutive for each of the periods presented. We determined basic and diluted net income per limited partner unit as set forth in the following tables:



	Three Months Ended September 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⁾	$	4,794		$	916		$	9		$	209		$	5,928
Less: Distributable earnings ⁽²⁾	8,200			1,566			14			280			10,060
Distributions in excess of earnings	$	(3,406	)	$	(650	)	$	(5	)	$	(71	)	$	(4,132	)
Weighted average units outstanding ⁽³⁾	21,915			4,185			39			461			26,600
Distributable earnings per unit ⁽⁴⁾	$	0.37		$	0.37		$	0.36
Overdistributed earnings per unit ⁽⁵⁾	(0.16		)	(0.16		)	(0.13		)
Net income per limited partner unit (basic and diluted)	$	0.21		$	0.21		$	0.23


⁽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 $107 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 $0.3575 per unit, or $1.43 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $443 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.



	Three Months Ended September 30, 2017
	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⁾	$	3,911		$	1,200		$	16		$	148		$	5,275
Less: Distributable earnings ⁽²⁾	7,030			$	2,260		29			223			9,542
Distributions in excess of earnings	$	(3,119	)	$	(1,060	)	$	(13	)	$	(75	)	$	(4,267	)
Weighted average units outstanding ⁽³⁾	19,538			6,278			84			461			26,361
Distributable earnings per unit ⁽⁴⁾	$	0.36		$	0.36		$	0.35
Overdistributed earnings per unit ⁽⁵⁾	(0.16		)	(0.17		)	(0.16		)
Net income per limited partner unit (basic and diluted)	$	0.20		$	0.19		$	0.19


⁽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 $57 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution of $0.345 per unit, or $1.38 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $392 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners 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.



	For the Nine Months Ended September 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⁾	$	15,337		$	3,246		$	33		$	624		$	19,240
Less: Distributable earnings ⁽²⁾	24,432			4,665			42			805			29,944
Distributions in excess of earnings	$	(9,095	)	$	(1,419	)	$	(9	)	$	(181	)	$	(10,704	)
Weighted average units outstanding ⁽³⁾	21,480			4,569			46			461			26,556
Distributable earnings per unit ⁽⁴⁾	$	1.14		$	1.02		$	0.91
Overdistributed earnings per unit ⁽⁵⁾	(0.42		)	(0.31		)	(0.20		)
Net income per limited partner unit (basic and diluted)	$	0.72		$	0.71		$	0.71


⁽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 $291 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the per unit distributions paid of $0.3525 per unit for the three months ended March 31, 2018, $0.355 per unit for the three months ended June 30, 2018, and $0.3575 per unit distributable for the three months ended September 30, 2018, representing a year-to-date distribution amount of $1.065 per unit. Amounts presented for each class of units include a proportionate amount of the $881 thousand distributed and $443 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.



	For the Nine Months Ended September 30, 2017
	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⁾	$	13,421		$	5,021		$	75		$	462		$	18,979
Less: Distributable earnings ⁽²⁾	19,782			6,697			91			600			27,170
Distributions in excess of earnings	$	(6,361	)	$	(1,676	)	$	(16	)	$	(138	)	$	(8,191	)
Weighted average units outstanding ⁽³⁾	17,380			6,661			98			461			24,600
Distributable earnings per unit ⁽⁴⁾	$	1.14		$	1.01		$	0.93
Overdistributed earnings per unit ⁽⁵⁾	(0.37		)	(0.25		)	(0.16		)
Net income per limited partner unit (basic and diluted)	$	0.77		$	0.76		$	0.77


⁽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 $109 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 $0.335 per unit for the three months ended March 31, 2017, $0.34 per unit for the three months ended June 30, 2017 and $0.345 per unit for the three months ended September 30, 2017, representing a year-to-date distribution amount of $1.02 per unit. Amounts presented for each class of units include a proportionate amount of the $1,177 thousand distributed to holders of the Equity-classified Phantom Units pursuant to the distribution equivalent rights granted under the USD Partners 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.

4. REVENUES

We recognize revenue from contracts with customers by applying the provisions of ASC 606, Revenue from Contracts with Customers. We recognize revenue under the core principle to depict the transfer of control to our customers of goods or services in an amount reflecting the consideration for which we expect to be entitled. In order to achieve the core principle, we apply the following five step approach:


(1)	identify the contract with a customer;


(2)	identify the performance obligations in the contract;


(3)	determine the transaction price;


(4)	allocate the transaction price to the performance obligations in the contract; and


(5)	recognize revenue when a performance obligation is satisfied.

We define a performance obligation as a promise in a contract to transfer a distinct good or service to the customer, which also represents the unit of account under ASC 606. We allocate the transaction price in a contract to each distinct performance obligation, which we recognize as revenue when, or as, the performance obligation is satisfied. For contracts with multiple performance obligations, we allocate the transaction price in the contract to each performance obligation using our best estimate of the standalone selling price for each distinct good or service in the contract, utilizing market-based and cost-plus margin inputs. We have elected to account for sales taxes received from customers on a net basis.

We applied the right-to-invoice practical expedient to contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

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 13. Segment Reporting for our disaggregated revenues by segment. Additionally, the below tables summarize the geographic data for our revenues:



	Three Months Ended September 30, 2018
	U.S.		Canada		Total
	(in thousands)
Third party	$	10,802	$	11,858	$	22,660
Related party	$	2,199	$	4,727	$	6,926



	Three Months Ended September 30, 2017
	U.S.		Canada		Total
	(in thousands)
Third party	$	8,749	$	12,287	$	21,036
Related party	$	1,231	$	4,737	$	5,968



	Nine Months Ended September 30, 2018
	U.S.		Canada		Total
	(in thousands)
Third party	$	33,970	$	35,875	$	69,845
Related party	$	5,013	$	14,038	$	19,051



	Nine Months Ended September 30, 2017
	U.S.		Canada		Total
	(in thousands)
Third party	$	29,824	$	39,456	$	69,280
Related party	$	3,571	$	9,091	$	12,662

Terminalling Services Revenues

We derive a majority of our revenues from contracts to provide terminalling services, which include pipeline transportation, storage, loading and unloading of crude oil and related products from and into railcars and trucks, as well as the transloading of biofuels from railcars into trucks. Our terminalling services agreements for crude oil and related products are generally established under multi-year, take-or-pay provisions that require monthly payments from our customers for their minimum monthly volume commitments in exchange for our performance of the terminalling services enumerated above. Our terminalling services for biofuels typically require monthly payments for actual volumes handled. Variable consideration, such as volume-based pricing, included in our agreements is typically resolved within the applicable accounting period.

We recognize revenue for the terminalling services we provide based upon the contractual rates set forth in our agreements related to throughput volumes. We recognize revenue over time as we render services based on the throughput delivered as this best represents the value we provide to customers for our services. Substantially all of the contracted capacity at our Casper, Hardisty and Stroud terminals is contracted under multi-year agreements that contain “take-or-pay” provisions where we are entitled to the payment of minimum monthly commitment fees from our customers, regardless of whether the specified throughput to which the customer committed is achieved.

Our terminalling services agreements generally grant our customers make-up rights that allow them to load volumes in excess of their minimum monthly commitment in future periods, without additional charge, to the extent capacity is available for the excess volume. With respect to the Casper terminal, the make-up rights generally expire within the three-month period, representing a calendar quarter, for which the volumes were originally committed. With respect to the Hardisty and Stroud terminals, the make-up rights typically expire, if unused, in subsequent periods up to six months following the period for which the volumes were originally committed. We 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. Breakage rates are regularly evaluated and modified as necessary to reflect our current expectations and experience. If we do not expect to be entitled to a breakage amount, we defer the recognition of revenue associated with volumes that are below the minimum monthly commitment until we determine that the likelihood that the customer will be able to make up the minimum volume is remote. If we expect to be entitled to a breakage amount, we estimate the expected breakage and recognize the expected breakage amount as revenue in proportion to the trend of rights exercised by the customer.

Fleet Services Revenues

Fleet services contracts provide for the sourcing of railcar fleets and related logistics and maintenance services. We allocate revenue between the lease and service components based on relative standalone values, typically utilizing market-based and cost-plus margin estimates, and account for each component under the applicable accounting guidance. We record revenues for fleet leases on a gross basis, since we are deemed the primary obligor for the services.

We recognize revenue for fleet leases and related party administrative services ratably over the lease contract period as services are consistently provided throughout the period. Revenue for reimbursable costs is recognized on a gross basis on our consolidated statements of income as “Freight and other reimbursables,” as the costs are incurred. We have deferred revenues for amounts collected in advance from customers in our Fleet services segment, which will be recognized as revenue as the underlying services are performed pursuant to the terms of our lease contracts. We have prepaid rent associated with these deferred revenues on our railcar leases, which we will recognize as expense as these railcars are used.

Railroad Incentives

In December 2013, USD Terminals Canada ULC, or USDTC, entered into a binding agreement with Canadian Pacific Railway Limited, which we refer to as CP, effective with the commencement of the Hardisty terminal operations in June 2014, whereby in consideration for CP being the sole rail freight transportation service provider at the Hardisty terminal for certain customers, CP agreed to pay USDTC an average incentive payment amount of C$100 per railcar shipped up to a maximum of C$12.5 million through mid-2017. We recognized the amounts we received in “Other income, net” in our consolidated statements of income, as we utilized the services of CP pursuant to the terms of the agreement. Such amounts were not material for any period presented herein and the agreement terminated in June 2017.

Remaining Performance Obligations

The transaction price allocated to the remaining performance obligations associated with our terminalling and fleet services agreements as of September 30, 2018 are as follows for the periods indicated:



	For the three months ended December 31, 2018		2019		2020		Thereafter		Total
	(in thousands)
Terminalling Services ^{(1) (2)}	$	24,513	$	91,692	$	57,458	$	80,668	$	254,331
Fleet Services	257		1,030		1,030		2,324		4,641
Total	$	24,770	$	92,722	$	58,488	$	82,992	$	258,972

⁽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 0.7769 U.S. dollars per one Canadian dollar at September 30, 2018.

⁽²⁾ Includes fixed monthly minimum commitment fees per contracts and excludes constrained variable consideration for rate-escalation 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 $188 thousand and $34 thousand as of September 30, 2018 and December 31, 2017, respectively, 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, which will be recognized as revenue when earned pursuant to the terms of our contractual arrangements. We have included contract liabilities with third-party customers of $3.1 million and $3.3 million as of September 30, 2018 and December 31, 2017, respectively, in “Deferred revenue.” We have included contract liabilities with related party customers of $1.6 million as of September 30, 2018 and December 31, 2017, 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 nine months ended September 30, 2018:



	December 31, 2017		Cash Additions for Customer Prepayments		Revenue Recognized			September 30, 2018
	(in thousands)
Customer prepayments	$	3,291	$	3,071	$	(3,291	)	$	3,071
Customer prepayments — related party ⁽¹⁾	$	1,576	$	1,558	$	(1,576	)	$	1,558


⁽¹⁾	Includes contract liabilities associated with customer prepayments from related parties. Refer to Note 11. Transactions with Related Parties for additional discussion of deferred revenues associated with related parties.

Deferred Revenue — Fleet Leases

Our deferred revenue also includes advance lease payments from customers of our Fleet services business, which will be recognized as 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 fleet services deferred revenues, which we will recognize as expense concurrently with our recognition of the associated revenue. We have included $0.4 million at September 30, 2018 and December 31, 2017 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 that we entered into during 2014 in connection with the development of our Hardisty terminal. The collaborative arrangement is further discussed in Note 9. 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:



	September 30,
	2018		2017
	(in thousands)
Cash and cash equivalents	$	7,361	$	7,831
Restricted Cash	5,834		5,138
Total cash, cash equivalents and restricted cash	$	13,195	$	12,969

6. PROPERTY AND EQUIPMENT

Our property and equipment consist of the following as of the dates indicated:



	September 30, 2018			December 31, 2017			Estimated Depreciable Lives (Years)
	(in thousands)						Estimated Depreciable Lives (Years)
Land	$	10,162		$	10,245		N/A
Trackage and facilities	126,561			128,568			10-30
Pipeline	16,336			16,336			20-25
Equipment	16,522			12,926			3-20
Furniture	66			67			5-10
Total property and equipment	169,647			168,142
Accumulated depreciation	(28,207		)	(22,369		)
Construction in progress ⁽¹⁾	677			800
Property and equipment, net	$	142,117		$	146,573


⁽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.

Depreciation expense associated with Property and equipment totaled $2.1 million for the three months ended September 30, 2018 and 2017, and $6.4 million and $5.7 million for the nine months ended September 30, 2018 and 2017, respectively.

7. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Our goodwill originated from our acquisition of the Casper terminal, which is included in our Terminalling services segment. As of September 30, 2018, the carrying amount of our goodwill was $33.6 million.

We test goodwill for impairment annually based on the carrying values of our reporting units on the first day of the third quarter of each year or more frequently if events or changes in circumstances suggest that the fair value of a reporting unit is less than its carrying value. During the third quarter of 2018, we completed our annual goodwill impairment analysis and determined that the fair value of the Casper terminal reporting unit exceeded its carrying value at July 1, 2018. An impairment charge would have resulted if our estimate of the fair value of the Casper terminal reporting unit was approximately 20% less than the amount determined. The critical assumptions used in our analysis include the following:


(1)	A weighted average cost of capital of 11%;


(2)	A capital structure consisting of approximately 40% debt and 60% equity;


(3)	A range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics, from 8.25x to 9.25x; and


(4)	A range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 9.0x to 10.0x.

We measured the fair value of our Casper terminal reporting unit by using an income analysis, market analysis and transaction analysis with weightings of 50%, 25% and 25%, respectively. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our Casper terminal. We have not observed any events or circumstances subsequent to our analysis that would suggest the fair value of our Casper terminal is below its carrying amount as of September 30, 2018.

Intangible Assets

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



	September 30, 2018			December 31, 2017
	(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	(36,178		)	(26,731		)
Other	(31		)	(23		)
Total accumulated amortization	(36,209		)	(26,754		)
Total intangible assets, net	$	89,857		$	99,312

Amortization expense associated with intangible assets totaled $3.2 million for each of the three months ended September 30, 2018 and 2017 and $9.5 million for each of the nine months ended September 30, 2018 and 2017.

8. DEBT

We have a senior secured credit agreement, the Credit Agreement that consists of a $400 million revolving credit facility (subject to the limits set forth therein), the Revolving Credit Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Agreement is a five year committed facility that matures on October 15, 2019. On November 2, 2018, we amended and restated our Credit Agreement as discussed in more detail in Note 19. Subsequent Events.

Previously, the Credit Agreement included a $300 million Revolving Credit Facility and a $100 million term loan (borrowed in Canadian dollars), the Term Loan Facility, which we repaid in March 2017. As we repaid amounts outstanding on the Term Loan Facility, the availability on our Revolving Credit Facility was automatically increased to the full $400 million of credit available under the Credit Agreement.

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. We have the ability to increase the maximum amount of credit available under the Credit Agreement, as amended, by an aggregate amount of up to $100 million to a total facility size of $500 million, subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions. The Revolving Credit Facility includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the

Revolving Credit Facility are guaranteed by our restricted subsidiaries (as such term is defined in our senior secured credit facility) 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:



	September 30, 2018			December 31, 2017
	(in thousands)
Revolving Credit Facility	201,000			202,000
Less: Deferred financing costs, net	(753		)	(1,373		)
Total long-term debt, net	$	200,247		$	200,627

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



	September 30, 2018		December 31, 2017
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	400.0	$	400.0
Less: Revolving Credit Facility amounts outstanding	201.0		202.0
Letters of credit outstanding	—		—
Available under Credit Agreement ⁽¹⁾	$	199.0	$	198.0


⁽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.

The average interest rate on our outstanding indebtedness was 4.72% and 4.00% at September 30, 2018 and December 31, 2017, respectively. 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 September 30, 2018, 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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Interest expense on the Credit Agreement	$	2,611	$	2,172	$	7,379	$	6,862
Amortization of deferred financing costs	216		216		646		646
Total interest expense	$	2,827	$	2,388	$	8,025	$	7,508

9. 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 $5.3 million and $6.0 million of expenses for the three months ended September 30, 2018 and 2017, respectively, and $16.1 million and $16.8 million for the nine months ended September 30, 2018 and 2017, respectively which are presented as “Pipeline fees” in our consolidated statements of income.

10. 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 September 30, 2018 and December 31, 2017, 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.



	September 30, 2018
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	27	$	—	$	7
Deferred revenue	—		20		—
	$	27	$	20	$	7



	December 31, 2017
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	30	$	—	$	—
Deferred revenue	—		284		—
	$	30	$	284	$	—

We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,983 railcars to the VIEs, but we have retained certain rights and obligations with respect to the servicing of these railcars.

During the quarter ended September 30, 2018, we provided no explicit or implicit financial or other support to these VIEs that were not previously contractually required.

11. 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 owns 7,371,672 of our common units and all 4,185,418 of our subordinated units representing a combined 43.4% limited partner interest in us. USDG also provides us with general and administrative support services necessary for the operation and management of our business.

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.

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.

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 September 30, 2018 and 2017, were $1.9 million and $1.5 million, respectively, and for the nine months ended September 30, 2018 and 2017 were $5.6 million and $4.3 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At September 30, 2018 and December 31, 2017, we had balances payable related to these costs of $0.4 million and $0.2 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 terminal 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 terminal customer during the 12 months prior to expiration. We also granted USDG the right to develop other projects at the Stroud terminal in exchange for the payment to us of market-based compensation for the use of our property for such development projects. 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.”

Contribution of Capital at the Stroud Terminal

Pursuant to the Marketing Services Agreement discussed above, USDM provided a temporary steaming solution and constructed a permanent steaming solution at the Stroud terminal to alleviate operational railcar unloading issues that resulted from cold weather at the terminal. The construction of the steaming equipment was completed in July 2018 and contributed to us. The non-cash capital contribution that was valued at the original cost of constructing the asset, resulting in a $3.4 million increase in “Property and equipment” and the capital account of our general partner included in “General Partner units” on our September 30, 2018 consolidated balance sheet. We did not issue additional General Partner units in connection with this contribution.

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 terminal 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 terminal customer, the contracted term for the capacity held by USDM has been extended to June 30, 2020. USDM controls approximately 25% of the available monthly capacity of the Hardisty terminal at September 30, 2018. 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 from spot terminalling services provided by our Hardisty terminal on behalf of USDM pursuant to the terms of its existing agreements with us. We include amounts received pursuant to these arrangements as revenue in the table below under “Terminalling services — related party.”

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Terminalling services — related party	$	5,715	$	4,737	$	15,414	$	9,091
Fleet leases — related party	984		1,013		2,951		2,794
Fleet services — related party	227		218		682		776
Freight and other reimbursables — related party	—		—		4		1
	$	6,926	$	5,968	$	19,051	$	12,662

We had the following amounts outstanding with USD and affiliates on our consolidated balance sheets as of September 30, 2018 and December 31, 2017:



	September 30, 2018		December 31, 2017
	(in thousands)
Accounts receivable — related party⁽¹⁾	$	903	$	410
Accounts payable — related party ⁽²⁾	$	439	$	—
Other current and non-current assets — related party⁽³⁾	$	193	$	253
Deferred revenue— related party ⁽⁴⁾	$	1,968	$	1,986


⁽¹⁾	Represents the amounts of receivables outstanding from USD and affiliates for the periods indicated.


⁽²⁾	Represents the amounts of payables outstanding to USD and affiliates for the periods indicated


⁽³⁾	Represents a contract asset associated with our lease agreement with USDM.


⁽⁴⁾	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 nine months ended September 30, 2018, 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 their 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)
February 1, 2018	February 12, 2018	February 16, 2018	$	4,045	$	238
April 26, 2018	May 7, 2018	May 11, 2018	$	4,074	$	249
July 27, 2018	August 7, 2018	August 14, 2018	$	4,103	$	261

12. 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.

13. 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. 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. We define Segment 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. 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.

The following tables summarize our reportable segment data:



	Three Months Ended September 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	21,728		$	—		$	—		$	21,728
Terminalling services — related party	5,715			—			—			5,715
Fleet leases	—			—			—			—
Fleet leases — related party	—			984			—			984
Fleet services	—			80			—			80
Fleet services — related party	—			227			—			227
Freight and other reimbursables	644			208			—			852
Freight and other reimbursables — related party	—			—			—			—
Total revenues	28,087			1,499			—			29,586
Operating costs
Subcontracted rail services	3,674			—			—			3,674
Pipeline fees	5,267			—			—			5,267
Fleet leases	—			984			—			984
Freight and other reimbursables	644			208			—			852
Operating and maintenance	1,292			68			—			1,360
Selling, general and administrative	1,346			401			2,609			4,356
Depreciation and amortization	5,271			—			—			5,271
Total operating costs	17,494			1,661			2,609			21,764
Operating income (loss)	10,593			(162		)	(2,609		)	7,822
Interest expense	—			—			2,827			2,827
Gain associated with derivative instruments	—			—			(413		)	(413		)
Foreign currency transaction loss (gain)	(30		)	3			(62		)	(89		)
Other income, net	(1		)	—			—			(1		)
Provision for (benefit from) income taxes	(431		)	5			(4		)	(430		)
Net income (loss)	$	11,055		$	(170	)	$	(4,957	)	$	5,928



	Three Months Ended September 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	19,805		$	—	$	—		$	19,805
Terminalling services — related party	4,737			—		—			4,737
Fleet leases	—			643		—			643
Fleet leases — related party	—			1,013		—			1,013
Fleet services	—			470		—			470
Fleet services — related party	—			218		—			218
Freight and other reimbursables	—			118		—			118
Freight and other reimbursables — related party	—			—		—			—
Total revenues	24,542			2,462		—			27,004
Operating costs
Subcontracted rail services	2,340			—		—			2,340
Pipeline fees	5,973			—		—			5,973
Fleet leases	—			1,656		—			1,656
Freight and other reimbursables	—			118		—			118
Operating and maintenance	654			95		—			749
Selling, general and administrative	1,395			210		2,093			3,698
Depreciation and amortization	5,254			—		—			5,254
Total operating costs	15,616			2,079		2,093			19,788
Operating income (loss)	8,926			383		(2,093		)	7,216
Interest expense	—			—		2,388			2,388
Loss associated with derivative instruments	667			—		—			667
Foreign currency transaction loss (gain)	(20		)	4		(441		)	(457		)
Other income, net	(52		)	—		—			(52		)
Provision for (benefit from) income taxes	(770		)	196		(31		)	(605		)
Net income (loss)	$	9,101		$	183	$	(4,009	)	$	5,275



	Nine Months Ended September 30, 2018
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	65,560		$	—		$	—		$	65,560
Terminalling services — related party	15,414			—			—			15,414
Fleet leases	—			—			—			—
Fleet leases — related party	—			2,951			—			2,951
Fleet services	—			505			—			505
Fleet services — related party	—			682			—			682
Freight and other reimbursables	2,088			1,692			—			3,780
Freight and other reimbursables — related party	3			1			—			4
Total revenues	83,065			5,831			—			88,896
Operating costs
Subcontracted rail services	10,047			—			—			10,047
Pipeline fees	16,109			—			—			16,109
Fleet leases	—			2,961			—			2,961
Freight and other reimbursables	2,091			1,693			—			3,784
Operating and maintenance	3,336			217			—			3,553
Selling, general and administrative	4,133			961			8,458			13,552
Depreciation and amortization	15,807			—			—			15,807
Total operating costs	51,523			5,832			8,458			65,813
Operating income (loss)	31,542			(1		)	(8,458		)	23,083
Interest expense	—			—			8,025			8,025
Gain associated with derivative instruments	—			—			(1,823		)	(1,823		)
Foreign currency transaction loss (gain)	32			(4		)	(211		)	(183		)
Other expense, net	71			—			—			71
Provision for (benefit from) income taxes	(2,265		)	21			(3		)	(2,247		)
Net income (loss)	$	33,704		$	(18	)	$	(14,446	)	$	19,240



	Nine Months Ended September 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	65,463		$	—	$	—		65,463
Terminalling services — related party	$	9,091		$	—	$	—		9,091
Fleet leases	—			1,929		—			1,929
Fleet leases — related party	—			2,794		—			2,794
Fleet services	—			1,405		—			1,405
Fleet services — related party	—			776		—			776
Freight and other reimbursables	110			373		—			483
Freight and other reimbursables — related party	—			1		—			1
Total revenues	74,664			7,278		—			81,942
Operating costs
Subcontracted rail services	6,148			—		—			6,148
Pipeline fees	16,802			—		—			16,802
Fleet leases	—			4,723		—			4,723
Freight and other reimbursables	110			374		—			484
Operating and maintenance	1,765			285		—			2,050
Selling, general and administrative	3,795			694		6,714			11,203
Depreciation and amortization	15,164			—		—			15,164
Total operating costs	43,784			6,076		6,714			56,574
Operating income (loss)	30,880			1,202		(6,714		)	25,368
Interest expense	170			—		7,338			7,508
Loss associated with derivative instruments	1,279			—		—			1,279
Foreign currency transaction loss (gain)	(33		)	6		(500		)	(527		)
Other income, net	(65		)	—		—			(65		)
Provision for (benefit from) income taxes	(2,140		)	511		(177		)	(1,806		)
Net income (loss)	$	31,669		$	685	$	(13,375	)	$	18,979

Segment Adjusted EBITDA

The following table provides a reconciliation of Segment Adjusted EBITDA to “Net cash provided by operating activities:”



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	15,814		$	14,076		$	47,197		$	46,336
Fleet services	(162		)	383			(1		)	1,202
Corporate activities ⁽¹⁾	(1,171		)	(1,147		)	(4,163		)	(3,752		)
Total Adjusted EBITDA	14,481			13,312			43,033			43,786
Add (deduct):
Amortization of deferred financing costs	216			216			646			646
Deferred income taxes	(731		)	(647		)	(3,269		)	(293		)
Changes in accounts receivable and other assets	5,836			2,822			(578		)	1,512
Changes in accounts payable and accrued expenses	(4,767		)	2,033			(1,789		)	947
Changes in deferred revenue and other liabilities	(150		)	(1,176		)	(386		)	(3,913		)
Interest expense, net	(2,827		)	(2,384		)	(8,025		)	(7,500		)
Benefit from income taxes	430			605			2,247			1,806
Foreign currency transaction gain ⁽²⁾	89			457			183			527
Other income	—			4			—			25
Non-cash contract asset ⁽³⁾	51			—			154			—
Net cash provided by operating activities	$	12,628		$	15,242		$	32,216		$	37,543


⁽¹⁾	Corporate activities represent shared service and financing transactions that are not allocated to our established reporting segments.


⁽²⁾	Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.


⁽³⁾	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 agreements. Refer to Note 4. Revenues — Contract Assets for more information.

14. 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. One of our subsidiaries, USD Rail LP, has elected to be classified as an entity taxable as a corporation for U.S. federal income tax purposes. 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 loss of $0.3 million and $0.7 million for the three and nine months ended September 30, 2018, respectively, and 34% as applied to its taxable income of $0.9 million and $1.9 million for the three and nine months ended September 30, 2017, respectively.

Foreign Income Taxes

Our Canadian operations are conducted through entities that are subject to Canadian federal and provincial income taxes which are determined using the combined federal and provincial income tax rate of 27% applied to the taxable income of our Canadian operations for the three and nine months ended September 30, 2018 and 2017.

Tax Effects of ASC 606 Adoption

In conjunction with our adoption of ASC 606, we recognized revenues with respect to each prior period for amounts that were previously deferred, as well as the associated previously deferred pipeline fees. Refer to Note 2. Recent Accounting Pronouncements for a comprehensive discussion regarding our adoption of ASC 606. We also 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 nine months ended September 30, 2018. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 will be fully recognized ratably during 2018. The deferred tax recovery of $0.9 million (representing C$1.2 million) for the three months ended September 30, 2018 and $2.7 million (representing C$3.6 million) for the nine months ended September 30, 2018 contributed to “Benefit from income taxes” for the three and nine months ended September 30, 2018.

Estimated Annual Effective Income Tax Rate

The reconciliation between income tax based on the U.S. federal statutory income tax rate and our effective income tax is presented below:



	Three Months Ended September 30,										Nine Months Ended September 30,
	2018					2017					2018					2017
	(in thousands)
Income tax expense at the U.S. federal statutory rate	$	1,154		21	%	$	1,588		34	%	$	3,568		21	%	$	5,839		34	%
Amount attributable to partnership not subject to income tax	(1,582		)	(29	)%	(2,418		)	(52	)%	(5,483		)	(32	)%	(8,132		)	(47	)%
Foreign income tax rate differential	(108		)	(2	)%	199			4	%	(494		)	(3	)%	553			3	%
Other	56			1	%	28			1	%	12			—	%	39			—	%
State income tax expense (benefit) ⁽¹⁾	2			—	%	(21		)	—	%	(4		)	—	%	(139		)	(1	)%
Change in valuation allowance	48			1	%	19			—	%	154			1	%	34			—	%
Benefit from income taxes	$	(430	)	(8	)%	$	(605	)	(13	)%	$	(2,247	)	(13	)%	$	(1,806	)	(11	)%


⁽¹⁾	Net of the federal income tax expense or benefit for the deduction associated with state income taxes.

We determined our year-to-date 2018 income tax using an estimated annual effective income tax rate on a consolidated basis for fiscal year 2018. This rate incorporates the applicable rates of the various domestic and foreign tax jurisdictions to which we are subject.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Current income tax expense (benefit):
U.S. federal income tax	$	—		$	289		$	4		$	662
U.S. federal operating loss carryforward	—			56			—			(200		)
State income tax expense (benefit)	2			(17		)	(4		)	(126		)
Canadian federal and provincial income taxes expense (benefit)	299			(286		)	1,022			(1,849		)
Total current income tax expense (benefit)	301			42			1,022			(1,513		)
Deferred income tax expense (benefit):
U.S. federal income tax expense (benefit)	—			(164		)	16			10
Canadian federal and provincial income taxes benefit	(731		)	(483		)	(3,285		)	(303		)
Total change in deferred income tax benefit	(731		)	(647		)	(3,269		)	(293		)
Benefit from income taxes	$	(430	)	$	(605	)	$	(2,247	)	$	(1,806	)

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:



	September 30, 2018
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Other assets	$	16		$	—		$	16
Prepaid expenses	—			—			—
Capital loss carryforwards	—			469			469
Operating loss carryforwards	138			—			138
Deferred income tax liabilities
Unbilled revenue	—			(276		)	(276		)
Deferred revenues	—			(816		)	(816		)
Property and equipment	—			(15		)	(15		)
Valuation allowance	(154		)	(469		)	(623		)
Deferred income tax liability, net	$	—		$	(1,107	)	$	(1,107	)



	December 31, 2017
	U.S.		Foreign			Total
	(in thousands)
Deferred income tax assets
Other assets	$	16	$	—		$	16
Prepaid expenses	—		1,731			1,731
Capital loss carryforwards	—		469			469
Deferred income tax liabilities
Unbilled revenue	—		(284		)	(284		)
Deferred revenues	—		(5,607		)	(5,607		)
Property and equipment	—		(346		)	(346		)
Valuation allowance	—		(469		)	(469		)
Deferred income tax asset (liability), net	$	16	$	(4,506	)	$	(4,490	)

We had a $0.7 million U.S. federal loss carryforward remaining as of September 30, 2018, and none as of December 31, 2017. Our U.S. federal loss carryforward was generated in 2018 and does not expire under currently enacted tax law. Our Canadian loss carryforward was $4.5 million and $4.6 million as of September 30, 2018 and December 31, 2017, 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 not have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of September 30, 2018 and December 31, 2017.

Refer to Note 18. Supplemental Cash Flow Information for information regarding amounts paid for income taxes.

15. 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 one-month LIBOR falls below the established floor rate of 1.7%, and the counterparty will pay us if the one-month LIBOR exceeds the 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.

Foreign Currency Derivatives

We derive a significant portion of our cash flows from our Hardisty terminal operations in the province of Alberta, Canada, which are denominated in Canadian dollars. As a result, fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar could have a significant effect on our results of operations, cash flows and financial position. We endeavor to limit our foreign currency risk exposure using various types of derivative financial instruments with characteristics that effectively reduce or eliminate the impact to us of declines in the exchange rate for a specified value of Canadian dollar denominated cash flows we expect to exchange into U.S. dollars. We have not entered into any derivative financial instruments to mitigate our exposure to changes in foreign currency exchange rates for 2018 or any future periods.

In April 2016, we entered into four separate forward contracts with an aggregate notional amount of C$33.5 million to manage our exposure to fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar resulting from our Canadian operations during the 2017 calendar year. Each forward contract effectively fixed the exchange rate we received for each Canadian dollar we sold to the counterparty. One of these forward contracts settled at the end of each fiscal quarter during 2017 and secured an exchange rate where a Canadian dollar was exchanged for an amount between 0.7804 and 0.7809 U.S. dollars.

Commodity Derivatives

In June 2017, as a part of our purchase of the Stroud terminal and related facilities, we acquired crude oil used by the prior owner for line fill in the crude oil pipeline and tank bottoms for the storage tanks at the Stroud terminal. We agreed to sell the approximately 18,000 barrels, or bbl, of crude oil used for tank bottoms in July 2017, and the approximately 13,000 bbl of crude oil used for line fill in October 2017, to an unrelated party at a price which varies with the price of crude oil during the months of July and October of 2017. In June 2017, we entered into two separate fixed-for-floating swap contracts with an aggregate notional amount of 31,778 bbl, to manage our exposure to fluctuating crude oil prices. Each swap contract effectively fixed the price that we received upon our delivery of the crude oil. The first contract for approximately 18,000 bbl settled in July 2017 at $47.20 per barrel and the second for approximately 13,000 bbl settled in October 2017 at $47.70 per barrel.

In September 2017, we also acquired crude oil used by the prior owner of the Stroud terminal for tank bottoms in a leased storage tank at a third-party facility in Cushing, Oklahoma. We agreed to sell this crude oil in October 2017 to an unrelated party at a price which varies with the price of crude oil during the month of October. We entered into a fixed-for-floating swap contract with an aggregate notional amount of 30,000 bbl to manage our exposure to the variability in crude oil prices during the month of October 2017. The swap contract effectively fixed the price we received upon our delivery of the crude oil and settled in October 2017 at $47.90 per barrel.

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:



	September 30, 2018		December 31, 2017
	(in thousands)
Other non-current assets	$	2,044	$	183

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 September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(in thousands)
Loss (gain) associated with derivative instruments	$	(413	)	$	667	$	(1,823	)	$	1,279

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 contract for the periods indicated:



	At September 30, 2018								At December 31, 2017
		Notional		Interest Rate Parameters		Fair Value			Fair Value
						(in thousands)
Collar Agreements Maturing in 2022
Ceiling		$	100,000,000	2.5	%	$	2,328		$	938
Floor		$	100,000,000	1.7	%	(284		)	(755		)
Total						$	2,044		$	183

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 Master Agreement, which governs our financial contracts and include master netting agreements, 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.



	September 30, 2018
	Current assets		Non-current assets		Current liabilities		Non-current liabilities			Total
	(in thousands)
Fair value of derivatives — gross presentation	$	—	$	2,328	$	—	$	—		$	2,328
Effects of netting arrangements	—		—		—		(284		)	$	(284	)
Fair value of derivatives — net presentation	$	—	$	2,328	$	—	$	(284	)	$	2,044



	December 31, 2017
	Current assets		Non-current assets		Current liabilities		Non-current liabilities			Total
	(in thousands)
Fair value of derivatives — gross presentation	$	—	$	938	$	—	$	—		$	938
Effects of netting arrangements	—		—		—		(755		)	$	(755	)
Fair value of derivatives — net presentation	$	—	$	938	$	—	$	(755	)	$	183

16. 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.

Our Class A units are limited partner interests in us that entitle the holders to nonforfeitable distributions that are 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, are considered participating securities. Our Class A units do not have voting rights and vest in four equal annual installments over the four years following the consummation of our initial public offering, or IPO, only if we grow our annualized distributions each year. If we do not achieve positive distribution growth in any of these years, the Class A units that would otherwise vest for that year will be forfeited. The Class A units contain a conversion feature, which, upon vesting, provides for the conversion of the Class A units into common units based on a conversion factor that is tied to the level of our distribution growth for the applicable year. The conversion factor was 1.00 for the first vesting tranche, 1.50 for the second vesting tranche, 1.00 for the third vesting tranche and will be no more than 2.00 for the fourth and final vesting tranche. In February 2018, pursuant to the terms set forth in our partnership agreement, the third vesting tranche of 38,750 Class A units vested. We determined that, upon conversion, each vested Class A unit would receive one common unit based upon our distributions paid for the four preceding quarters. As a result, 38,750 Class A units were converted into 38,750 common units.

Our partnership agreement provides that, while any subordinated units remain outstanding, holders of our common units and Class A units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to our minimum quarterly distribution 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 percent 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 2018, pursuant to the terms set forth in our partnership agreement, we converted the third 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 363,070 vested during the first nine months of 2018, of which 245,929 were converted into our common units after 117,141 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 17. 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.

17. UNIT BASED COMPENSATION

Class A units

Our Class A units vest over a four year period if established distribution growth target thresholds are met each year of the four year vesting period. In February 2018, pursuant to the terms set forth in our partnership agreement, the third 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. The grant date average fair value of all Class A units was $25.71 per unit at September 30, 2018 and 2017.

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



	Nine Months Ended September 30,
	2018		2017
Class A units outstanding at beginning of period	82,500		138,750
Vested	(38,750	)	(46,250	)
Forfeited	(5,000	)	(10,000	)
Class A units outstanding at end of period	38,750		82,500

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 September 30,					Nine months ended September 30,
	2018		2017			2018		2017
	(in thousands)
Selling, general and administrative	$	42	$	(124	)	$	216	$	108

For the nine months ended September 30, 2018, we had forfeitures of 5,000 Class A units and no forfeitures for the three months ended September 30, 2018. We had forfeitures of 10,000 Class A units during the three and nine months ended September 30, 2017. We have elected to account for actual forfeitures as they occur rather than applying an estimated forfeiture rate when determining compensation expense.

Each holder of a Class A unit is 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 are forfeited are reclassified to unit based compensation expense when we determine that the Class A units are not expected to vest. We recognized compensation expense of $15 thousand for the nine months ended September 30, 2018, for distributions

paid on Class A units that were forfeited. We did not recognize any compensation expense for distributions paid on Class A units that were not expected to vest during the three months ended September 30, 2018. For the three and nine months ended September 30, 2017, we recognized compensation expense of $30 thousand for distributions paid on forfeited Class A units.

Long-term Incentive Plan

In 2018 and 2017, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 553,940 and 695,099 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our A/R LTIP. At September 30, 2018, we had 1,819,665 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, 2017	24,999		1,111,849		$	10.90
Granted	34,611		487,839		$	11.54
Vested	(24,999	)	(338,071	)	$	10.86
Forfeited	—		(56,740	)	$	11.07
Phantom Unit awards at September 30, 2018	34,611		1,204,877		$	11.18



	Director and Independent Consultant Phantom Units		Employee Phantom Units		Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2016	64,830		730,808		$	8.51
Granted	24,999		639,955		$	12.79
Vested	(64,830	)	(204,456	)	$	8.47
Forfeited	—		(56,083	)	$	10.94
Phantom Unit awards at September 30, 2017	24,999		1,110,224		$	10.91

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, 2017	8,333		27,794	$	11.29
Granted	11,348		20,142	$	11.55
Vested	(8,333	)	—	$	12.80
Phantom Unit awards at September 30, 2018	11,348		47,936	$	12.13



	Director and Independent Consultant Phantom Units		Employee Phantom Units	Weighted-Average Grant Date Fair Value Per Phantom Unit
Phantom Unit awards at December 31, 2016	21,610		21,615	$	7.70
Granted	8,333		19,812	$	12.80
Vested	(21,610	)	—	$	6.39
Phantom Unit awards at September 30, 2017	8,333		41,427	$	11.15

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 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. With respect to the Phantom Units granted to consultants and independent directors of our general partner and its affiliates domiciled in the United States, we revalue the unvested Phantom Units outstanding at the end of each reporting period throughout the requisite service period and record 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 September 30, 2018 and 2017, we recognized $1.4 million and $1.1 million, respectively, and $4.1 million and $2.9 million for the nine months ended September 30, 2018 and 2017, respectively, of compensation expense associated with outstanding Phantom Units. As of September 30, 2018, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $10.9 million, which we expect to recognize over a weighted average period of 2.62 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 September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Equity-classified Phantom Units ⁽¹⁾	$	440	$	388	$	1,269	$	1,048
Liability-classified Phantom Units	21		17		55		48
Total	$	461	$	405	$	1,324	$	1,096

⁽¹⁾

We had no reclassifications to unit based compensation expense for the three months ended September 30, 2018 and reclassifications of $61 thousand to unit based compensation expense for the three months ended September 30, 2017 for DERs paid in relation to Phantom Units that have been forfeited. For the nine months ended September 30, 2018 and 2017, we reclassified $84 thousand and $64 thousand, respectively, to unit based compensation expense for Phantom Unit forfeitures.

18. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2018		2017
	(in thousands)
Cash paid (received) for income taxes	$	626	$	(1,250	)
Cash paid for interest	$	7,499	$	7,102

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:



	Nine Months Ended September 30,
	2018		2017
	(in thousands)
Loss associated with disposal of assets	$	73	$	18
Amortization of deferred financing costs	646		646
Total	$	719	$	664

Non-cash Capital Contribution

In July 2018, USDG made a $3.4 million non-cash capital contribution of tangible property to us, representing a non-cash investing activity for cash flow purposes. Refer to Note 11. Transactions with Related Parties for additional discussion of the non-cash capital contribution.

19. SUBSEQUENT EVENTS

Distribution to Partners

On October 25, 2018, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.3575 per unit, or $1.43 per unit on an annualized basis, for the three months ended September 30, 2018. The distribution represents an increase of $0.0025 per unit, or 0.7% over the prior quarter distribution per unit, and is 24.3% over our minimum quarterly distribution per unit. The distribution will be paid on November 14, 2018, to unitholders of record at the close of business on November 6, 2018. The distribution will include payment of $5.2 million to our public common unitholders, $14 thousand to the Class A unitholders, an

aggregate of $4.1 million to USDG as a holder of our common units and the sole owner of our subordinated units and $272 thousand to USD Partners GP LLC for its general partner interest and as holder of the IDR.

Amended and Restated Credit Agreement

On November 2, 2018, we entered into an Amended and Restated Credit Agreement (the “A/R Credit Agreement”) with a syndicate of lenders. The A/R Credit Agreement replaces the existing Credit Agreement and is a four year committed facility that matures on November 2, 2022, with a borrowing capacity of $385 million subject to the limits set forth therein. The A/R Credit Agreement includes 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 under the A/R Credit Agreement to a total facility size of $500 million, subject to receiving increased commitments from lenders and satisfaction of certain conditions. Additionally, under the A/R Credit Agreement the applicable margin we are charged on LIBOR-based borrowings has been reduced by 25 basis points to a range from 2.00% to 3.00% which is dependent on our consolidated net leverage ratio. Further, the A/R Credit Agreement eliminates the ability to borrow in Canadian dollars, but keeps the financial covenants, substantially consistent with the existing Credit Agreement. The A/R Credit Agreement contains customary representations, warranties, covenants and events of default for facilities of this type.

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, 2017. 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, 2017 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.

Throughout the following discussion 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 is also developing an expansion project at the Partnership's Hardisty terminal, also referred to as Hardisty South, which when completed will add 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.

According to Natural Resources Canada, effectively all of Canada’s crude oil exports are transported to the United States. During 2016 and 2017, multiple supply outages at major oil sands production facilities reduced the volume of production seeking transportation from Western Canada into the United States. As such, widely-expected pipeline transportation constraints did not materialize during that time.

This year as oil sands production facilities have returned to normal operating levels and new production capacity has been brought online, Western Canadian crude oil supplies have continued to exceed available pipeline takeaway capacity. As a result, WCS spreads in relation to key benchmarks have discounted to levels that are near double the 2017 average. To date in 2018, apportionment levels on the primary heavy crude oil pipelines of the largest export pipeline system from Western Canada to the U.S. have averaged above 40%, and apportionment on the light crude oil pipelines on the system have averaged approximately 40% in recent months (representing the percentage of barrels nominated that were not shipped due to pipeline capacity constraints). As a result, inventory levels have grown and remained at historic highs, as barrels not shipped were placed in storage. Furthermore, customer activity at our Hardisty origination terminal has increased substantially as strategically-located rail capacity has provided an export outlet for growing oil sands production.

During the fourth quarter of 2018 to date, the WCS to West Texas Intermediate, or WTI, crude oil spread has widened to $40-$50 per barrel from $16-$36 per barrel during the third quarter of 2018, resulting from increased Western Canadian crude oil supply, the lack of sufficient pipeline takeaway capacity from the region and seasonal turnaround maintenance at Midwest refineries. We expect the WCS to WTI spread to tighten from current levels in the remainder of the fourth quarter, as refineries in the Midwest complete seasonal maintenance and ramp back up to full capacity and Canadian railroads continue to facilitate increased shipments of crude oil unit trains, which has alleviated some of the congestion out of Western Canada. However, we expect the WCS to WTI spread to remain at 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. Current WCS versus WTI spreads published by Bloomberg through 2023 average $25-$27 per barrel and are indicative of the continued imbalance between supply and takeaway capacity. Despite the growing demand for railroad capacity, we anticipate that the railroads will be able to service the capacity at our Hardisty terminal by the end of the fourth quarter 2018.

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 2018, the Canadian Association of Petroleum Producers, or CAPP, projected that the supply of crude oil from Western Canada will grow by approximately 750,000 bpd by 2020 and 1.1 million bpd by 2025 relative to 2017 levels. The forecasted supply of crude oil from Western Canada remains well in excess of existing pipeline takeaway capacity out of the region.

In the last twelve months, the industry experienced a consolidation of Western Canadian oil sands producing assets among active Canadian producers. We expect this will 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.

As a result, 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 due to regulatory or other headwinds. 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 advantaged 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

In November 2018, we entered into a four year extension with a Canadian based oil infrastructure focused company at our Hardisty terminal. The customer has significantly increased its position by more than doubling its contracted capacity at the terminal. The extension contains consistent take-or-pay terms with minimum monthly payments and rates that exceed those of the original terminalling services agreement with this customer.

In September 2018, we entered into a four year extension agreement with Cenovus Energy Inc., significantly increasing their previous position from 7% to 25% of our Hardisty terminal’s capacity. In June 2018, we also entered into a multi-year renewal and extension of approximately 25% of the capacity at our Hardisty rail terminal with one of our existing investment grade customers. The renewals contain consistent take-or-pay terms with minimum monthly payments and rates that exceed those of the original terminalling services agreements.

To date, we have renewed and extended approximately 65% of the capacity at our Hardisty terminal through mid-2022, with approximately 42% extended through mid-2023. These contract renewals will generate meaningful increases in revenue for us and are estimated to replace approximately 80% of our Hardisty terminal’s current cash flows, on an annualized basis, over the next three years starting in July 2019.

Additionally, in June 2018, USD Group LLC, or USDG, announced that it executed a five-year, take-or-pay terminalling services agreement with a high quality refiner customer. The agreement is for trans-loading capacity at the Hardisty rail terminal with an expected start date in late 2018. This new agreement provides commercial support for the construction of additional capacity at the Hardisty terminal pursuant to USDG’s existing development rights. The Hardisty South project will add one 120-railcar unit train of transloading capacity per day and is expected to be substantially complete by the end of 2018. Once it is in service and fully contracted, we believe the Hardisty South expansion could present an attractive acquisition opportunity for us pursuant to our existing right of first offer with respect to midstream projects developed by USDG.

During March and April 2018, the initial customer of the Stroud terminal (“Stroud customer”), an investment grade multi-national energy company, secured the remaining available capacity at the Stroud terminal from USD Marketing LLC, an affiliate of USDG, for periods beginning in the second quarter of 2018 and ending in June 2019 and January 2020, pursuant to the Marketing Services Agreement established with the Partnership at the time of the Stroud acquisition.

Similarly, the Partnership obtained origination capacity from customers of the Hardisty terminal and immediately contracted with the Stroud customer for this capacity at the same economic terms as the initial customer agreements. Consistent with the new agreements for destination capacity at the Stroud terminal, the Hardisty origination capacity was contracted for corresponding periods beginning in the second quarter of 2018 and ending in June 2019 and January 2020 (the later representing a seven month extension over the original Hardisty contract term). As a result, the Stroud customer increased its contracted position from approximately 25% to nearly half of the existing capacity at the Hardisty terminal.

How We Generate Revenue

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

Terminalling Services

The terminalling services segment includes a network of strategically-located terminals that provide customers with railcar loading and/or unloading capacity, as well as related logistics services, for crude oil and biofuels.

Substantially all of our cash flows are generated from multi-year, take-or-pay terminal services agreements with customers at our Hardisty, Casper and Stroud terminals 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.

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 September 30, 2018, our railcar fleet consisted of 2,183 railcars, which we leased from various railcar manufacturers and financial entities, including 1,808 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 1,983 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 3 years as of September 30, 2018. At our customer’s request, we facilitated the early termination of the lease and associated master fleet services agreement with respect to 300 C&I railcars in July 2018. These agreements otherwise would have expired in 2022 and we were made whole in connection with this termination.

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	12,628		$	15,242		$	32,216		$	37,543
Add (deduct):
Amortization of deferred financing costs	(216		)	(216		)	(646		)	(646		)
Deferred income taxes	731			647			3,269			293
Changes in accounts receivable and other assets	(5,836		)	(2,822		)	578			(1,512		)
Changes in accounts payable and accrued expenses	4,767			(2,033		)	1,789			(947		)
Changes in deferred revenue and other liabilities	150			1,176			386			3,913
Interest expense, net	2,827			2,384			8,025			7,500
Benefit from income taxes	(430		)	(605		)	(2,247		)	(1,806		)
Foreign currency transaction gain ⁽¹⁾	(89		)	(457		)	(183		)	(527		)
Other income	—			(4		)	—			(25		)
Non-cash contract asset ⁽²⁾	(51		)	—			(154		)	—
Adjusted EBITDA	14,481			13,312			43,033			43,786
Add (deduct):
Cash received (paid) for income taxes ⁽³⁾	(177		)	2,664			(626		)	1,250
Cash paid for interest	(2,678		)	(2,165		)	(7,499		)	(7,102		)
Maintenance capital expenditures	(18		)	(274		)	(98		)	(472		)
Distributable cash flow	$	11,608		$	13,537		$	34,810		$	37,462


⁽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 agreements. 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⁾	Includes a partial refund of $2.6 million (representing C$3.4 million) received in the three and nine months ended September 30, 2017, for our 2016 foreign income taxes. Also includes a partial refund of $0.7 million (representing C$0.9 million) received in the nine months ended September 30, 2017, for our 2015 foreign income taxes.

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 rent 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, 2017. 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.

Customer Contract Expirations and Renewals

A customer of our Casper terminal, whose existing terminalling services agreement with us expires in October 2018, did not exercise its option to extend the agreement for an additional one-year term. We executed a two-month extension of the agreement at reduced volumes and continue to actively negotiate a longer term agreement. We recently executed a three-year agreement with a new customer and have several other new customers utilizing capacity at the terminal with whom we are actively pursuing term agreements. Although we cannot make any assurances regarding the outcome of these negotiations, we continue to expect growth in Western Canada crude oil production to exceed near-term pipeline takeaway capacity, which provides us with unique opportunities to meet the needs of producers and refiners with this strategically-positioned and scalable asset, particularly given current political and economic challenges facing new and proposed infrastructure projects.

Regulatory Environment

Our operations are subject to federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling of liquid hydrocarbons and biofuels. Additionally, we are subject to regulations governing railcar design and evolving regulations pertaining to the shipment of liquid hydrocarbons and biofuels by rail. Please read “Item 1. Business-Impact of Regulation” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Certain of the railroads serving our terminals have in the past and are currently considering imposing tariffs, fees or other limitations on the utilization of older railcar designs. These tariffs, fees and limitations could have the effect of imposing limits on the use of railcars that are more stringent than current regulatory standards, and could reduce the size of the overall railcar fleet available to be loaded at our terminals and increase the costs of obtaining usable railcars. Similar to other industry participants, compliance with existing and any additional environmental laws and regulations, or the imposition of additional tariffs, fees or limitations on the transportation of crude oil in certain railcars or all railcars by the railroads, could increase our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities, or the costs of our customers, which may reduce the attractiveness of rail transportation and limit our ability to extend existing agreements or attract new customers. Our master fleet services agreements generally obligate our customers to pay for modifications and other required repairs to our leased and managed railcar fleet. However, we cannot assure that we

will be able to successfully pass all such regulatory costs on to our customers. While changes in laws and regulations could indirectly affect Adjusted EBITDA and DCF, we believe that consumers of our services place additional value on utilizing established and reputable third-party providers to satisfy their rail terminalling and logistics needs, which may allow us to increase market share relative to customer-owned operations or smaller operators that lack an established track record of safety and regulatory compliance.

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.

Stroud Terminal Asset Purchase

Our operating results include costs in the third quarter of 2017 and revenue and costs for the three and nine month periods ended September 30, 2018, associated with the operations of the Stroud terminal that we purchased in June 2017.

Conclusion of Customer Agreements

Our historical operations include a unit train-capable ethanol destination terminal in San Antonio, Texas, that we ceased operating in May of 2017, upon the conclusion of our customer’s agreement with us. Additionally, one of our terminalling services agreements at our Casper terminal concluded in August 2017.

Income Tax Expense

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers, or ASC 606, which provides a single comprehensive model for revenue recognition. We adopted the requirements of ASC 606 effective January 1, 2018, using the full retrospective method. As a result, we recognized revenues with respect to each prior period for amounts that were previously deferred, as well as the associated previously deferred pipeline fees. 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 comprehensive discussion regarding our adoption of ASC 606.

In conjunction with our adoption of ASC 606, we also 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 nine months ended September 30, 2018. For Canadian tax purposes, the previously deferred revenue, net of previously deferred expenses associated with our adoption of ASC 606 will be fully recognized ratably during 2018. The deferred tax recovery of $0.9 million (representing C$1.2 million) for the three months ended September 30, 2018 and $2.7 million (representing C$3.6 million) for the nine months ended September 30, 2018, contributed to the Benefit from income taxes for the three and nine months ended September 30, 2018.

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Operating income (loss)
Terminalling services	$	10,593		$	8,926		$	31,542		$	30,880
Fleet services	(162		)	383			(1		)	1,202
Corporate and other	(2,609		)	(2,093		)	(8,458		)	(6,714		)
Total operating income	7,822			7,216			23,083			25,368
Interest expense, net	2,827			2,388			8,025			7,508
Loss (gain) associated with derivative instruments	(413		)	667			(1,823		)	1,279
Foreign currency transaction gain	(89		)	(457		)	(183		)	(527		)
Other expense (income), net	(1		)	(52		)	71			(65		)
Benefit from income taxes	(430		)	(605		)	(2,247		)	(1,806		)
Net income	$	5,928		$	5,275		$	19,240		$	18,979

Summary Analysis of Operating Results

Changes in our operating results for the three and nine months ended September 30, 2018, as compared with our operating results for the three and nine months ended September 30, 2017, were primarily driven by:

•

our average daily terminal throughput increased to 98,936 bpd for the nine months ended September 30, 2018, from 31,100 bpd for the same period in 2017, due primarily to increased activity by customers of our Hardisty terminal resulting from increased Western Canadian crude oil production and constrained pipeline takeaway capacity out of the region, coupled with the commencement of operations at our Stroud terminal in the fourth quarter of 2017;

•

the positive impact to operating income of our terminalling services business associated with the commencement of operations of our Stroud terminal in October 2017, which contributed $8.2 million of incremental operating income during the current year. The increase was partially offset by the impact of the customer agreements at our Casper and San Antonio terminals that concluded in August 2017 and May 2017, respectively;


•	a decrease in the operating income of our fleet services business associated with the conclusion of contracts for approximately 600 railcars;


•	an increase in corporate and other operating costs primarily due to higher unit based compensation expenses and consulting costs associated with accounting projects;


•	an increase in interest expense due to a rising interest rate environment;


•	a derivative instrument gain associated with our interest rate derivative financial instruments; and


•	a benefit from income taxes associated with the partial recovery of a deferred tax liability due to our adoption of ASC 606.

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Revenues
Terminalling services	$	27,443		$	24,542		$	80,974		$	74,554
Freight and other reimbursables	644			—			2,091			110
Total revenues	28,087			24,542			83,065			74,664
Operating costs
Subcontracted rail services	3,674			2,340			10,047			6,148
Pipeline fees	5,267			5,973			16,109			16,802
Freight and other reimbursables	644			—			2,091			110
Operating and maintenance	1,292			654			3,336			1,765
Selling, general and administrative	1,346			1,395			4,133			3,795
Depreciation and amortization	5,271			5,254			15,807			15,164
Total operating costs	17,494			15,616			51,523			43,784
Operating income	10,593			8,926			31,542			30,880
Interest expense	—			—			—			170
Loss associated with derivative instruments	—			667			—			1,279
Foreign currency transaction loss (gain)	(30		)	(20		)	32			(33		)
Other expense (income), net	(1		)	(52		)	71			(65		)
Benefit from income taxes	(431		)	(770		)	(2,265		)	(2,140		)
Net income	$	11,055		$	9,101		$	33,704		$	31,669
Average daily terminal throughput (bpd)	121,983			37,883			98,936			31,100

Three months ended September 30, 2018 compared with three months ended September 30, 2017

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $3.5 million to $28.1 million for the three months ended September 30, 2018, as compared with the three months ended September 30, 2017. This increase was primarily due to the commencement of operations at our Stroud terminal in October 2017, which contributed an additional $5.7 million of revenue to our Terminalling services business in the three months ended September 30, 2018. This increase to revenue was partially offset by declines in revenue at our Casper terminal resulting from the conclusion of a customer agreement in August 2017.

Our average daily terminal throughput increased to 121,983 bpd for the three months ended September 30, 2018 from 37,883 bpd for the same period in 2017, due primarily to increased activity by customers of our Hardisty terminal coupled with the commencement of operations at our Stroud terminal in the fourth quarter of 2017. 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. 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 do increase the variable operating costs associated with our Hardisty terminal, as discussed below.

Our terminalling service revenue for the three months ended September 30, 2018, would have been $0.7 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2018, was the same as the average exchange rate for the three months ended September 30, 2017.

Operating Costs

The operating costs of our Terminalling services segment increased $1.9 million to $17.5 million for the three months ended September 30, 2018, compared with $15.6 million for the three months ended September 30, 2017. The increase is attributable to the commencement of our Stroud terminal operations in October 2017, which added $1.8 million of incremental operating costs during the three months ended September 30, 2018, and an increase in variable operating costs at our Hardisty terminal associated with the increase in throughput activity.

Our terminalling services operating costs for the three months ended September 30, 2018, would have been $0.4 million more if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2018, was the same as the average exchange rate for the three months ended September 30, 2017.

Subcontracted rail services. Our subcontracted rail services costs increased $1.3 million to $3.7 million for the three months ended September 30, 2018. This increase is directly correlated with the increased throughput activity at our Hardisty terminal. Additionally, the commencement of operations at our Stroud terminal in October 2017 added $0.6 million of incremental costs during the three months ended September 30, 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 $0.7 million to $5.3 million for the three months ended September 30, 2018, primarily due to additional direct operating costs associated with the higher volumes at our Hardisty terminal, which reduces the amounts we pay to Gibson. These pipeline fees were also lower due to a decrease in revenues recognized at the Hardisty terminal resulting from lower average exchange rates for the period.

Operating and maintenance. Operating and maintenance expense increased $0.6 million to $1.3 million for the three months ended September 30, 2018, as compared with $0.7 million for three months ended September 30, 2017. The increased operating and maintenance expense are attributable to our Stroud terminal which commenced operations in October 2017, and added $0.6 million of incremental operating costs during the three months ended September 30, 2018. Operating and maintenance expense also increased as a result of increased throughput activity at our Hardisty terminal.

Other Expenses

Loss associated with derivative instruments. We had no loss associated with our derivative instruments for the three months ended September 30, 2018, as compared with a loss of $0.7 million for the three months ended September 30, 2017. We entered into derivatives in 2016 for the purpose of mitigating our exposure to fluctuations in foreign currency exchange rates, all of which were settled in 2017. In addition, we entered into commodity swap contracts to fix the price we received from our sale of the crude oil we acquired with our purchase of Stroud in June 2017.

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 by the Canadian federal and provincial governments at enacted rates which currently total 27% on a combined basis.

Our benefit from income taxes for the Terminalling services segment decreased $0.3 million to $0.4 million for the three months ended September 30, 2018, as compared with the three months ended September 30, 2017. In connection with our adoption of ASC 606, we recovered a deferred tax liability associated with previously deferred

revenues net of previously deferred pipeline fees. During the three months ended September 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 expect to recover the remaining deferred tax liability associated with our adoption of ASC 606 ratably during 2018. The recovery of a portion of the deferred tax liability was partially offset by current and deferred income tax expense we recognized for the three months ended September 30, 2018. For the same period in 2017, we had a benefit from taxes due to a revision of our estimates for the three months ended September 30, 2017, based on refunds that we received after filing our 2016 tax return in 2017.

Nine months ended September 30, 2018 compared with nine months ended September 30, 2017

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $8.4 million to $83.1 million for the nine months ended September 30, 2018, as compared with $74.7 million for the nine months ended September 30, 2017. This increase was primarily due to the commencement of operations at our Stroud terminal in October 2017, which contributed an additional $15.1 million of revenue to our Terminalling services business during the nine months ended September 30, 2018. This increase to revenue was partially offset by declines in revenue resulting from the conclusion of customer agreements at our San Antonio facility in May 2017 and our Casper terminal in August 2017.

Our average daily terminal throughput increased to 98,936 bpd for the nine months ended September 30, 2018, from 31,100 bpd for the same period in 2017, due primarily to increased activity by customers at our Hardisty terminal and the fourth quarter of 2017 commencement of operations at our Stroud 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. Our terminalling services revenues are recognized based upon the contractual terms set forth in our agreements that 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 do increase the variable operating costs associated with our Hardisty terminal, as discussed below.

Our terminalling services revenue for the nine months ended September 30, 2018, would have been $0.7 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2018, was the same as the average exchange rate for the nine months ended September 30, 2017.

Operating Costs

The operating costs of our Terminalling services segment increased $7.7 million to $51.5 million for the nine months ended September 30, 2018, as compared with the nine months ended September 30, 2017. The increase is attributable to the commencement of operations at our Stroud terminal in October 2017, which added $5.8 million of incremental operating costs during the nine months ended September 30, 2018, and an increase in variable operating costs at our Hardisty terminal associated with the increase in throughput activity.

Our terminalling services operating costs for the nine months ended September 30, 2018, would have been $0.3 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2018, was the same as the average exchange rate for the nine months ended September 30, 2017.

Subcontracted rail services. Our subcontracted rail services costs increased $3.9 million to $10.0 million for the nine months ended September 30, 2018. This increase is directly correlated with the increased throughput activity at our Hardisty terminal. Additionally, the commencement of operations at our Stroud terminal in October 2017 added $1.8 million of incremental costs during the nine months ended September 30, 2018. These increases were partially offset by reduced costs associated with the conclusion of operations at our San Antonio facility in May 2017 and the conclusion of a customer agreement at our Casper terminal in August 2017.

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 $0.7 million to $16.1 million for the nine months ended September 30, 2018 due primarily to additional direct operating costs associated with higher throughput volumes at our Hardisty terminal, which reduce the amounts we pay to Gibson.

Operating and maintenance. Operating and maintenance expense increased $1.6 million to $3.3 million for the nine months ended September 30, 2018, as compared with $1.8 million for the nine months ended September 30, 2017. The increased operating and maintenance expense are attributable to our Stroud terminal which commenced operations in October 2017 and added $1.2 million of incremental operating costs during the nine months ended September 30, 2018. Operating and maintenance expense also increased as a result of increased throughput at our Hardisty terminal. These increases were partially offset by the conclusion of operations at our San Antonio terminal.

Selling, general and administrative. Selling, general and administrative expense increased $0.3 million to $4.1 million for the nine months ended September 30, 2018, primarily due to the addition of the Stroud terminal, partially offset by lower costs resulting from the conclusion of operations at our San Antonio terminal.

Depreciation and amortization. Depreciation and amortization expense increased $0.6 million to $15.8 million for the nine months ended September 30, 2018, primarily due to the additional assets of our Stroud terminal, which we acquired in June 2017 and began depreciating at that time.

Other Expenses

Interest expense. We had no interest expense for our Terminalling services segment for the nine months ended September 30, 2018, as compared with $0.2 million for the nine months ended September 30, 2017. We repaid all amounts outstanding on the Term Loan Facility in March 2017, which eliminated the interest expense of our Terminalling Services business directly attributable to the Term Loan Facility.

Loss associated with derivative instruments. We had no loss associated with derivative instruments for the nine months ended September 30, 2018, as compared with a loss of $1.3 million for the nine months ended September 30, 2017. We entered into derivatives in 2016 for the purpose of mitigating our exposure to fluctuations in foreign currency exchange rates, all of which were settled in 2017. In addition, we entered into commodity swap contracts to fix the price we received from our sale of the crude oil we acquired with our purchase of the Stroud terminal in June 2017.

Our benefit from income taxes for the Terminalling services segment increased $0.1 million to $2.3 million for the nine months ended September 30, 2018, as compared with the nine months ended September 30, 2017. In connection with our adoption of ASC 606, we recovered a deferred tax liability associated with previously deferred revenues net of previously deferred pipeline fees. During the nine months ended September 30, 2018, we recovered $2.7 million (C$3.6 million), representing a portion of that deferred tax liability, which produced a benefit from income taxes. We expect to recover the remaining deferred tax liability associated with our adoption of ASC 606 ratably during 2018. The recovery of a portion of the deferred tax liability was partially offset by current and deferred income tax expense we recognized for the nine months ended September 30, 2018. For the same period in 2017, we had a benefit from taxes due to a revision of our estimates based on refunds that we received after filing our 2016 tax return in 2017.

FLEET SERVICES

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(in thousands)
Revenues
Fleet leases	$	984		$	1,656	$	2,951		$	4,723
Fleet services	307			688		1,187			2,181
Freight and other reimbursables	208			118		1,693			374
Total revenues	1,499			2,462		5,831			7,278
Operating costs
Fleet leases	984			1,656		2,961			4,723
Freight and other reimbursables	208			118		1,693			374
Operating and maintenance	68			95		217			285
Selling, general and administrative	401			210		961			694
Total operating costs	1,661			2,079		5,832			6,076
Operating income (loss)	(162		)	383		(1		)	1,202
Foreign currency transaction loss (gain)	3			4		(4		)	6
Provision for (benefit from) income taxes	5			196		21			511
Net income	$	(170	)	$	183	$	(18	)	$	685

Three months ended September 30, 2018 compared with three months ended September 30, 2017

Revenues from our Fleet services segment decreased $1.0 million to $1.5 million for the three months ended September 30, 2018 from $2.5 million for the three months ended September 30, 2017. The decrease was primarily attributable to approximately 600 fewer railcars for the current quarter as compared with the same period in 2017, resulting from the conclusion of railcar leases, 300 of which concluded in July 2018. There was an accompanying decrease in Fleet lease expense of $0.7 million associated with this reduction in railcars. This decrease in revenue was offset by an increase in Freight and other reimbursables revenue, which represents customer reimbursements to us for freight and other charges that we have incurred on behalf of our customers and were exactly offset by a corresponding increase in Freight and other reimbursables operating cost. This increase in Freight and other reimbursables revenues is associated with increased customer storage costs.

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 entered into leases with third-party manufacturers of railcars and financial firms, which it has 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.

Nine months ended September 30, 2018 compared with nine months ended September 30, 2017

Revenues from our Fleet services segment decreased $1.4 million to $5.8 million for the nine months ended September 30, 2018, as compared with the same period in 2017. The decrease was primarily attributable to the reduction in fleet leases and fleet services revenues associated with approximately 600 fewer railcars leased during the nine months ended September 30, 2018, as compared with the same period of 2017, due to the conclusion of leases on these railcars. There was an accompanying decrease in Fleet lease expense of $1.8 million associated with this reduction in railcars. The decrease to fleet lease and services revenue was partially offset by an increase in Freight and other reimbursables revenue, which represents customer reimbursements to us for freight and other charges that we have incurred on their behalf and were exactly offset by a corresponding increase in Freight and other reimbursables operating cost. This increase in Freight and other reimbursables revenues and the associated operating costs is primarily due to railcar repairs related to returns and to increased customer storage costs.

CORPORATE ACTIVITIES

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Operating costs
Selling, general and administrative	$	2,609		$	2,093		$	8,458		$	6,714
Operating loss	(2,609		)	(2,093		)	(8,458		)	(6,714		)
Interest expense	2,827			2,388			8,025			7,338
Gain associated with derivative instruments	(413		)	—			(1,823		)	—
Foreign currency transaction loss (gain)	(62		)	(441		)	(211		)	(500		)
Provision for (benefit from) income taxes	(4		)	(31		)	(3		)	(177		)
Net loss	$	(4,957	)	$	(4,009	)	$	(14,446	)	$	(13,375	)

Three months ended September 30, 2018 compared with three months ended September 30, 2017

Costs associated with our corporate activities increased by $0.9 million to $5.0 million for the three months ended September 30, 2018. Our “Selling, general and administrative” expenses increased $0.5 million, primarily due to additional unit based compensation expense associated with the Phantom Units granted in February 2018 to directors and employees of our general partner and its affiliates. Our “Interest expense” increased $0.4 million primarily due to an increase in the interest rates we were charged under our Credit Agreement during the three months ended September 30, 2018, as compared with the same period of 2017. Partially offsetting these increases was a gain of $0.4 million resulting from the five-year interest rate derivative financial instruments we entered in November 2017 discussed below.

Effective November 2017, we entered into a five-year interest rate collar contract with a notional amount of $100 million. The interest rate collar establishes a range where we will pay the counterparty if the one-month LIBOR falls below the established floor rate of 1.70%, and the counterparty will pay us if the one-month LIBOR exceeds the established ceiling rate of 2.50%. The interest rate 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 predetermined ceiling or floor rates.

Nine months ended September 30, 2018 compared with nine months ended September 30, 2017

Costs associated with our corporate activities increased by $1.1 million to $14.4 million for the nine months ended September 30, 2018. Our “Selling, general and administrative” expenses increased $1.7 million, primarily due to additional unit based compensation expense associated with the Phantom Units granted in February 2018 to directors

and employees of our general partner and its affiliates. Also contributing to the increase were consulting costs associated with accounting projects to upgrade systems and implement new accounting standards. Our “Interest expense” increased $0.7 million due to an increase in the interest rates we were charged under our Credit Agreement during the nine months ended September 30, 2018, as compared with the same period of 2017. In addition, we had a decrease in benefit from income taxes of $0.2 million due to a change in our estimate for Texas Franchise tax expense in 2017. Partially offsetting the increase in costs associated with our corporate activities was a gain of $1.8 million resulting from the five-year interest rate derivative financial instruments we entered in November 2017 discussed below.

LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements include:


•	financing current operations;


•	servicing our debt;


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


•	making distributions to our unitholders.

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

Liquidity Sources

We expect our ongoing sources of liquidity to include borrowings under our senior secured credit agreement, issuances of debt securities and additional partnership interests, either privately or pursuant to our effective shelf registration statement, 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.

Credit Agreement

During the quarter ended September 30, 2018, we had a senior secured credit agreement, the Credit Agreement, comprised of a $400 million revolving credit facility (subject to the limits set forth therein), or the Revolving Credit Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders.

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. We have the ability to increase the maximum amount of credit available under the Credit Agreement, as amended, to a total facility size of $500 million, subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions. The Revolving Credit Facility includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the Revolving Credit Facility are guaranteed by our restricted subsidiaries (as such term is defined in our Credit Agreement) and are secured by a first priority lien on our assets and those of our restricted subsidiaries, other than certain excluded assets.

The average interest rate on our outstanding indebtedness, excluding the effects of any derivatives, was 4.72% and 4.00% at September 30, 2018 and December 31, 2017, respectively. 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 September 30, 2018, we were in compliance with the covenants set forth in our Credit Agreement.

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



	September 30, 2018		December 31, 2017
	(in millions)
Cash and cash equivalents ⁽¹⁾	$	7.4	$	7.9
Aggregate borrowing capacity under Credit Agreement	400.0		400.0
Revolving Credit Facility amounts outstanding	201.0		202.0
Letters of credit outstanding	—		—
Total available liquidity ⁽²⁾	$	206.4	$	205.9


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


⁽²⁾	Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 4.5 times our trailing 12-month consolidated EBITDA.

Energy Capital Partners must approve any additional issuances of equity by us, which determinations may be made free of any duty to us or our unitholders. 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 presents a summary of cash flows associated with our operating, investing and financing activities for the periods indicated:



	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by (used in):
Operating activities	$	32,216		$	37,543
Investing activities	(207		)	(26,708		)
Financing activities	(31,923		)	(15,246		)
Effect of exchange rates on cash	(679		)	242
Net change in cash, cash equivalents and restricted cash	$	(593	)	$	(4,169	)

Operating Activities

Net cash provided by operating activities decreased by $5.3 million to $32.2 million for the nine months ended September 30, 2018, from $37.5 million for the nine months ended September 30, 2017. The decrease in Net cash provided by operating activities is primarily attributable to the changes in cash flows derived from our operating results as discussed above in Results of Operations. While net income for the nine month periods ended September 30, 2018 and 2017 is relatively consistent, the net income for the 2018 period includes a significant amount of non-cash items

that increase net income, but do not increase cash flow, such as gains associated with derivative instruments, reductions to deferred income taxes, and other similar items. The lower operating cash flow for the nine months ended September 30, 2018 as compared with the same period of 2017, is primarily due to the increase in variable operating costs at our Hardisty terminal associated with the increased throughput activity of our customers that do not have a corresponding increase in revenues. Substantially all of the revenues at our Hardisty terminal are derived under take-or-pay arrangements with minimum monthly commitments collected from our customers regardless of throughput activity. In 2017, when throughput activity was substantially less, variable operating costs were lower than in 2018 when throughput activity increased. Also contributing to the decrease in Net cash provided by operating activities is the timing of receipts and payments on accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities decreased to $0.2 million for the nine months ended September 30, 2018 compared to $26.7 million for the nine months ended September 30, 2017. The use in 2017 was primarily attributable to our purchase of the Stroud terminal assets.

Financing Activities

Net cash used in financing activities increased to $31.9 million for the nine months ended September 30, 2018, from $15.2 million for the nine months ended September 30, 2017. We had net repayments on our long-term debt of $1.0 million for the nine months ended September 30, 2018, compared with net repayments of $22.3 million for the nine months ended September 30, 2017. The repayments of indebtedness in 2017 were attributable to the $33.7 million of net proceeds we received from the issuance of common units in May 2017. During the nine months ended September 30, 2018, we paid cash distributions of $29.6 million and participant withholding taxes associated with vested Phantom Units of $1.4 million, both of which exceeded amounts paid during the nine months ended September 30, 2017, for similar items.

Segment Adjusted EBITDA

The cash generated by our reporting segments represents one of our ongoing sources of liquidity. 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. We define Segment 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.

The following table provides a reconciliation of Segment Adjusted EBITDA to “Net cash provided by operating activities”:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	15,814		$	14,076		$	47,197		$	46,336
Fleet services	(162		)	383			(1		)	1,202
Corporate activities ⁽¹⁾	(1,171		)	(1,147		)	(4,163		)	(3,752		)
Total Adjusted EBITDA	14,481			13,312			43,033			43,786
Add (deduct):
Amortization of deferred financing costs	216			216			646			646
Deferred income taxes	(731		)	(647		)	(3,269		)	(293		)
Changes in accounts receivable and other assets	5,836			2,822			(578		)	1,512
Changes in accounts payable and accrued expenses	(4,767		)	2,033			(1,789		)	947
Changes in deferred revenue and other liabilities	(150		)	(1,176		)	(386		)	(3,913		)
Interest expense, net	(2,827		)	(2,384		)	(8,025		)	(7,500		)
Benefit from income taxes	430			605			2,247			1,806
Foreign currency transaction gain ⁽²⁾	89			457			183			527
Other income	—			4			—			25
Non-cash contract asset ⁽³⁾	51			—			154			—
Net cash provided by operating activities	$	12,628		$	15,242		$	32,216		$	37,543


⁽¹⁾	Corporate activities represent corporate and financing transactions that are not allocated to our established reporting segments.


⁽²⁾	Represents foreign exchange transaction amounts associated with activities between our U.S. and Canadian subsidiaries.


⁽³⁾	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 agreements. 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.

Terminalling Services Segment

Adjusted EBITDA from our Terminalling services segment increased $1.7 million to $15.8 million for the three months ended September 30, 2018, from $14.1 million for the three months ended September 30, 2017, and increased $0.9 million to $47.2 million for the nine months ended September 30, 2018 from $46.3 million for the nine months ended September 30, 2017. Refer to Results of Operations — By Segment — Terminalling Services for a discussion of the changes in terminalling services revenues and operating costs for the three and nine month periods ended September 30, 2018 compared with the three and nine month periods ended September 30, 2017 that contributed to the changes in Adjusted EBITDA for the respective periods. Additionally, for an analysis of the changes in working capital items, refer to the Operating activities analysis provided in the Cash Flow section above.

Fleet Services Segment

Adjusted EBITDA from our Fleet services business decreased $0.5 million to a negative $0.2 million for the three months ended September 30, 2018, compared with the three months ended September 30, 2017 and decreased $1.2 million to a loss of $1 thousand for the nine months ended September 30, 2018 from the nine months ended September 30, 2017. The decrease is primarily a result of the conclusion of railcar leases on approximately 600 railcars, which reduces the adjusted EBITDA we derive from this segment. Refer to Results of Operations — By Segment — Fleet Services for additional discussion of the changes in fleet services revenues and operating costs for the three and

nine month periods ended September 30, 2018 compared with the three and nine month periods ended September 30, 2017 that contributed to the changes in Adjusted EBITDA for the respective periods.

Cash Requirements

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

Capital Requirements

Our historical capital expenditures have primarily consisted of the costs to construct and acquire energy-related logistics assets. Our operations are expected to require investments to expand, upgrade or enhance existing 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. A majority of our assets have been in operation for fewer than five years. As a result, we do not expect to incur significant maintenance capital expenditures in the near-term to maintain the operating capacity of these assets. However, as the age of our assets increase, we expect to incur costs to maintain our assets in compliance with sound business practice, our contractual relationships and applicable regulatory requirements, some of which will be characterized as maintenance capital expenditures. We incurred $98 thousand of maintenance capital expenditures during the nine months ended September 30, 2018, primarily for replacement of technological equipment for our terminalling facilities. We record routine maintenance expenses we incur in connection with the operation of our assets in “Operating and maintenance” costs in our consolidated statements of income.

We had $0.3 million of expansion capital expenditures for the nine months ended September 30, 2018. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated by our operations, borrowings under our A/R 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 and investing needs. During the nine months ended September 30, 2018, 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 $21.0 million 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. The distribution of $0.3575 per unit that we expect to pay with respect to the three months ended September 30, 2018, equates to $9.6 million per quarter, or $38.5 million per year, based on the number of common, Class A, subordinated, and general partner units outstanding as of November 6, 2018. 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, although we do not currently have any such instruments in place.

SUBSEQUENT EVENTS

Refer to Note 19. 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 10. Nonconsolidated Variable Interest Entities to our consolidated financial statements included in Part I — Financial Information, Item 1. Financial Statements of this Report. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheets, and we do not expect any material impact on our cash flows, results of operations or financial condition as a result of these off-balance sheet arrangements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

There have been no changes to our critical accounting policies and estimates described in the Annual Report on Form 10-K for the year ended December 31, 2017, that have had a material impact on our consolidated financial statements and related notes, other than as discussed below.

Revenue


(1)	identify the contract with a customer;


(2)	identify the performance obligations in the contract;


(3)	determine the transaction price;


(4)	allocate the transaction price to the performance obligations in the contract; and


(5)	recognize revenue when a performance obligation is satisfied.

with multiple performance obligations, we allocate the transaction price in the contract to each performance obligation using our best estimate of the standalone selling price for each distinct good or service in the contract, utilizing market-based and cost-plus margin inputs. We have elected to account for sales taxes received from customers on a net basis.

We applied the right-to-invoice practical expedient to contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

Terminalling Services Revenues

We recognize revenue for the terminalling services we provide based upon the contractual rates set forth in our agreements related to throughput volumes. We recognize revenue over time as we render services based on the throughput delivered as this best represents the value we provide to customers for our services. All of the contracted capacity at our Casper, Hardisty and Stroud terminals is contracted under multi-year agreements that contain “take-or-pay” provisions where we are entitled to the payment of minimum monthly commitment fees from our customers, regardless of whether the specified throughput to which the customer committed is achieved.

Our terminalling services agreements grant our customers make-up rights that allow them to load volumes in excess of their minimum monthly commitment in future periods, without additional charge, to the extent capacity is available for the excess volume. With respect to the Casper terminal, the make-up rights generally expire within the three-month period, representing a calendar quarter, for which the volumes were originally committed. With respect to the Hardisty and Stroud terminals, the make-up rights typically expire, if unused, in subsequent periods up to six months following the period for which the volumes were originally committed. We 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. Breakage rates are regularly evaluated and modified as necessary to reflect our current expectations and experience. If we do not expect to be entitled to a breakage amount, we defer the recognition of revenue associated with volumes that are below the minimum monthly commitment until we determine that the likelihood that the customer will be able to make up the minimum volume is remote. If we expect to be entitled to a breakage amount, we estimate expected breakage and recognize the expected breakage amount as revenue in proportion to the trend of rights exercised by the customer.

Fleet Services Revenues

Our fleet services contracts provide for the sourcing of railcar fleets and related logistics and maintenance services. We allocate revenue between the lease and service components based on the relative standalone values, typically utilizing market-based and cost-plus margin estimates, and account for each component under the applicable accounting guidance. We record revenues for fleet leases on a gross basis, since we are deemed the primary obligor for the services.

We recognize revenue for fleet leases and related party administrative services ratably over the contract period as services are consistently provided throughout the period. Revenue for reimbursable costs is recognized on a gross basis on our consolidated statements of operations as “Freight and other reimbursables,” as the costs are incurred. We have deferred revenues for amounts collected in advance from customers in our Fleet services segment, which we will recognize as revenue as the underlying services are performed pursuant to the terms of our contracts. We have prepaid rent associated with these deferred revenues on our railcar leases, which we will recognize as expense as these railcars are used.

Railroad Incentives

In December 2013, USD Terminals Canada ULC, or USDTC, entered into a binding agreement with Canadian Pacific Railway Limited, which we refer to as CP, effective with the commencement of the Hardisty terminal operations in June 2014, whereby in consideration for CP being the sole rail freight transportation service provider at the Hardisty terminal for certain customers, CP agreed to pay USDTC an average incentive payment amount of C$100 per railcar shipped up to a maximum of C$12.5 million through mid-2017. We recognized these amounts in “Other income, net” in our consolidated statements of income, as we utilized the services of CP pursuant to the terms of the agreement.

Assessment of Recoverability of Goodwill

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. Currently, goodwill is only included in our Terminalling services segment as part of our Casper terminal reporting unit.

We do not amortize goodwill, but test it for impairment annually based on the carrying values of our reporting units on the first day of the third quarter of each year or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. Our assessment of the recoverability of goodwill is highly subjective due to frequent changes in economic conditions underlying the assumptions upon which the valuations are based and global factors affecting the prices for various grades of crude oil and demand for our services. In assessing our ability to recover the carrying value of goodwill, we make critical assumptions that include but are not limited to:


(1)	our projections of future financial performance;


(2)	our expectations for contract renewals for existing and additional capacity with current customers;


(3)	our ability to expand our services and attract new customers;


(4)	our expected market weighted average cost of capital;


(5)	an expected range of EBITDA multiples derived from equity prices of public companies with similar operating and investment characteristics; and


(6)	an expected range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses.

We recognize an impairment loss when the carrying amount of a reporting unit exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.

The $33.6 million balance of our goodwill originated from our acquisition of the Casper terminal in November 2015 and is wholly attributed to this reporting unit. We measured the fair value of our Casper terminal reporting unit using customary business valuation techniques including an income analysis, market analysis and transaction analysis, which we weighted at 50%, 25% and 25%, respectively. Our weighting of the measurement methods is consistent with weightings used to value organizations that are similar to the Casper terminal reporting unit. The critical assumptions used in our analysis include the following:


(1)	Capital expenditures for additional terminalling connectivity and unloading racks;


(2)	Expanding existing business and attracting new customers to produce approximately $15 to $20 million of incremental annual revenue;


(3)	A weighted average cost of capital of 11%;


(4)	A capital structure consisting of approximately 40% debt and 60% equity;


(5)	A range of EBITDA multiples derived from stock prices of public companies with similar operating and investment characteristics, from 8.25x to 9.25x; and


(6)	A range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 9.0x to 10.0x.

The key assumptions listed above were based upon economic and other operational conditions existing at or prior to the July 1, 2018, valuation date. Our weighted average cost of capital is subject to variability and is dependent upon such factors as changes in benchmark rates of interest established by the Federal Open Market Committee of the Federal Reserve Board, the British Bankers Association and other central banking regulatory authorities, as well as perceptions of risk and market uncertainty regarding our business, industry and those of our peers and our underlying capital structure. We expect our long-term underlying capital structure to approximate a weighting of 50% debt and 50% equity. Each of the above assumptions are likely to change due to economic uncertainty surrounding global and North American energy markets that are highly correlated with crude oil, natural gas and other energy-related commodity prices and other market factors.

Assumptions we make under the income approach include our projections of future financial performance of the Casper terminal reporting unit, which include our ability to obtain additional connectivity at the terminal, our ability to renew existing contracts and expand business with current customers, and our ability to enter into contracts with new customers and obtain additional commitments regarding the use of these facilities. To the extent that our assumptions vary from what we experience in the future, our projections of future financial performance underlying the fair value derived from the income approach for the Casper terminal reporting unit could yield results that are significantly different from those projected. Further, in the event we are unable to execute a majority of our growth plans underlying our financial projections for the Casper terminal reporting unit, we will likely realize an impairment of goodwill.

The EBITDA multiples we used to estimate the fair value of the Casper terminal reporting unit are subject to uncertainty associated with market conditions in the energy sector. We derived our assumptions based upon the EBITDA multiples from several comparable businesses that operate in the midstream energy sector, generally providing services associated with the transportation of energy-related products. The EBITDA multiples of each of these entities is affected by changes in the supply of and demand for energy-related products, which affects the demand for the services they provide. Declines in the production of energy-related products as well as lower demand for these products can reduce the operating results of these organizations and, accordingly, the multiples that market participants are willing to pay. Changes in the EBITDA multiples of these comparable businesses we use to estimate fair value could significantly affect the fair value of the Casper terminal reporting unit we derived using this approach.

The EBITDA multiples from executed purchase and sales transactions of businesses that are similar to our Casper terminal reporting unit we used to estimate the fair value are also subject to variability, which is dependent upon market conditions in the energy sector, as well as the perceived benefits the acquiring entity expects to derive from the transaction. The transactions comprising the pool occurred during the immediately preceding three years and future transactions may have no correlation to the EBITDA multiples for similar transactions in the future. Further deterioration in economic conditions in the energy sector could result in a greater number of distressed sales at lower EBITDA multiples than currently estimated. Additionally, a representative sample of transactions in the future may not provide a sufficient population upon which to derive an EBITDA multiple. These factors, among others, could cause our estimates of fair value for the Casper terminal reporting unit to vary significantly from the amounts determined under this method.

As indicated above, our estimate of fair value for the Casper terminal reporting unit required us to use significant unobservable inputs representative of Level 3 fair value measurements, including assumptions related to the future performance of our Casper terminal. During the third quarter of 2018, we completed our annual goodwill impairment analysis and determined that the fair value of the Casper terminal reporting unit exceeded its carrying value at July 1, 2018. An impairment charge would have resulted if our estimate of the fair value of the Casper terminal reporting unit was approximately 20% less than the amount determined. We have not observed any events or circumstances subsequent to our analysis that would suggest the fair value of our Casper terminal is below its carrying amount as of September 30, 2018.


Item 3.	Quantitative and Qualitative Disclosures about Market Risk.

We have not had any material changes in our market risk exposure that would affect the quantitative and qualitative disclosures presented in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017.

The following table presents summarized information about the fair values of our outstanding interest rate contracts for the periods indicated:



	At September 30, 2018								At December 31, 2017
		Notional		Interest Rate Parameters		Fair Value			Fair Value
						(in thousands)
Collar Agreements Maturing in 2022
Ceiling		$	100,000,000	2.5	%	$	2,328		$	938
Floor		$	100,000,000	1.7	%	(284		)	(755		)
Total						$	2,044		$	183


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 September 30, 2018. 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 September 30, 2018, 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 September 30, 2018, 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 contemplated to be brought against us.

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, 2017. No material changes to such risk factors have occurred during the three and nine months ended September 30, 2018.

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 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.


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

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 PARTNERS LP (Registrant)

		By:	USD Partners GP LLC, its General Partner

Date:	November 6, 2018	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	November 6, 2018	By:	/s/ Adam Altsuler
			Adam Altsuler Senior Vice President and Chief Financial Officer (Principal Financial Officer)