USD Partners LP - Quarter Report: 2017 June (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 June 30, 2017



¨	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 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO ¨

Indicate by check mark 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 ¨ (Do not check if smaller reporting company)
	Smaller reporting company ¨
	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 Act). YES ¨ NO x

As of August 4, 2017, there were 19,537,699 common units, 6,278,127 subordinated units, 82,500 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	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 4.	Controls and Procedures	54

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 6.	Exhibits	56
SIGNATURES		57

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, rail 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, 2016, and subsequent Quarterly Reports on Form 10-Q, which are 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 June 30,							Six Months Ended June 30,
	2017				2016			2017			2016
	(unaudited; in thousands, except per unit amounts)
Revenues
Terminalling services	$	21,977			$	23,459		$	45,536		$	45,482
Terminalling services — related party	2,518				1,756			4,258			3,406
Railroad incentives	6				22			21			37
Fleet leases	643				647			1,286			1,290
Fleet leases — related party	891				891			1,781			1,781
Fleet services	467				69			935			138
Fleet services — related party	279				684			558			1,368
Freight and other reimbursables	208				350			365			733
Freight and other reimbursables — related party	—				—			1			—
Total revenues	26,989				27,878			54,741			54,235
Operating costs
Subcontracted rail services	1,795				2,026			3,808			4,069
Pipeline fees	5,369				5,338			10,786			10,052
Fleet leases	1,534				1,538			3,067			3,071
Freight and other reimbursables	208				350			366			733
Operating and maintenance	594				783			1,301			1,653
Selling, general and administrative	2,362				2,073			4,677			4,967
Selling, general and administrative — related party	1,396				1,439			2,828			2,931
Depreciation and amortization	4,969				4,914			9,910			9,819
Total operating costs	18,227				18,461			36,743			37,295
Operating income	8,762				9,417			17,998			16,940
Interest expense	2,513				2,533			5,120			4,716
Loss (gain) associated with derivative instruments	401				(253		)	612			1,270
Foreign currency transaction gain	(100		)		(15		)	(70		)	(145		)
Other expense, net	3			—	—			8			—
Income before provision for income taxes	5,945				7,152			12,328			11,099
Provision for (benefit from) income taxes	(2,434		)		1,917			(1,249		)	3,714
Net income	$	8,379			$	5,235		$	13,577		$	7,385
Net income attributable to limited partner interests	$	8,185			$	5,131		$	13,265		$	7,238
Net income per common unit (basic and diluted)	$	0.35			$	0.23		$	0.58		$	0.32
Weighted average common units outstanding	17,329				14,182			16,283			13,546
Net income per subordinated unit (basic and diluted)	$	0.34			$	0.23		$	0.55		$	0.31
Weighted average subordinated units outstanding	6,278				8,371			6,856			8,969

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
	(unaudited; in thousands)
Net income	$	8,379	$	5,235		$	13,577	$	7,385
Other comprehensive income (loss) — foreign currency translation	1,214		(14		)	1,499		780
Comprehensive income	$	9,593	$	5,221		$	15,076	$	8,165

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six Months Ended June 30,
	2017			2016
	(unaudited; in thousands)
Cash flows from operating activities:
Net income	$	13,577		$	7,385
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	9,910			9,819
Loss associated with derivative instruments	612			1,270
Settlement of derivative contracts	390			1,036
Unit based compensation expense	2,016			1,697
Other	755			334
Changes in operating assets and liabilities:
Accounts receivable	(424		)	207
Accounts receivable — related party	179			1,760
Prepaid expenses and other current assets	(1,108		)	(460		)
Accounts payable and accrued expenses	(1,316		)	(1,961		)
Accounts payable and accrued expenses — related party	230			24
Deferred revenue and other liabilities	(3,545		)	2,729
Deferred revenue — related party	1,025			(629		)
Change in restricted cash	(230		)	(633		)
Net cash provided by operating activities	22,071			22,578
Cash flows from investing activities:
Additions of property and equipment	(25,773		)	(246		)
Net cash used in investing activities	(25,773		)	(246		)
Cash flows from financing activities:
Distributions	(16,142		)	(14,396		)
Vested phantom units used for payment of participant taxes	(1,072		)	(77		)
Net proceeds from issuance of common units	33,700			—
Proceeds from long-term debt	40,000			10,000
Repayments of long-term debt	(57,342		)	(18,902		)
Net cash used in financing activities	(856		)	(23,375		)
Effect of exchange rates on cash	49			439
Net change in cash and cash equivalents	(4,509		)	(604		)
Cash and cash equivalents – beginning of period	11,705			10,500
Cash and cash equivalents – end of period	$	7,196		$	9,896

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	June 30, 2017			December 31, 2016
	(unaudited; in thousands, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	7,196		$	11,705
Restricted cash	5,861			5,433
Accounts receivable, net	4,800			4,321
Accounts receivable — related party	—			219
Prepaid expenses	9,372			10,325
Other current assets	5,361			2,562
Total current assets	32,590			34,565
Property and equipment, net	148,626			125,702
Intangible assets, net	105,615			111,919
Goodwill	33,589			33,589
Other non-current assets	182			192
Total assets	$	320,602		$	305,967

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	976		$	2,221
Accounts payable and accrued expenses — related party	419			214
Deferred revenue, current portion	25,167			26,928
Deferred revenue, current portion — related party	5,481			4,292
Other current liabilities	2,904			3,513
Total current liabilities	34,947			37,168
Long-term debt, net	204,196			220,894
Deferred revenue, net of current portion	—			264
Deferred income tax liability, net	1,153			823
Total liabilities	240,296			259,149
Commitments and contingencies
Partners’ capital
Common units (19,537,699 and 14,185,599 outstanding at June 30, 2017 and December 31, 2016, respectively)	136,838			122,802
Class A units (92,500 and 138,750 outstanding at June 30, 2017 and December 31, 2016, respectively)	1,416			1,811
Subordinated units (6,278,127 and 8,370,836 outstanding at June 30, 2017 and December 31, 2016, respectively)	(58,378		)	(76,749		)
General partner units (461,136 outstanding at June 30, 2017 and December 31, 2016)	88			111
Accumulated other comprehensive income (loss)	342			(1,157		)
Total partners’ capital	80,306			46,818
Total liabilities and partners’ capital	$	320,602		$	305,967

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Six Months Ended June 30,
	2017					2016
	Units		Amount			Units		Amount
	(unaudited; in thousands, except unit amounts)
Common units
Beginning balance	14,185,599		$	122,802		11,947,127		$	141,374
Conversion of units	2,162,084		(19,047		)	2,138,959		(18,300		)
Common units issued for vested phantom units	190,016		(1,072		)	95,910		(77		)
Issuance of common units	3,000,000		33,700			—		—
Net income	—		9,422			—		4,361
Unit based compensation expense	—		1,694			—		1,053
Distributions	—		(10,661		)	—		(8,155		)
Ending balance	19,537,699		136,838			14,181,996		120,256
Class A units
Beginning balance	138,750		1,811			185,000		1,749
Conversion of units	(46,250	)	(606		)	(46,250	)	(871		)
Net income	—		59			—		48
Unit based compensation expense	—		232			—		534
Distributions	—		(80		)	—		(100		)
Ending balance	92,500		1,416			138,750		1,360
Subordinated units
Beginning balance	8,370,836		(76,749		)	10,463,545		(93,445		)
Conversion of units	(2,092,709	)	19,653			(2,092,709	)	19,171
Net income	—		3,784			—		2,829
Distributions	—		(5,066		)	—		(5,854		)
Ending balance	6,278,127		(58,378		)	8,370,836		(77,299		)
General Partner units
Beginning balance	461,136		111			461,136		220
Net income	—		312			—		147
Distributions	—		(335		)	—		(287		)
Ending balance	461,136		88			461,136		80
Accumulated other comprehensive income (loss)
Beginning balance			(1,157		)			(138		)
Cumulative translation adjustment			1,499					780
Ending balance			342					642
Total partners’ capital at June 30,			$	80,306				$	45,039

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 and refiners. Our principal assets include a network of crude terminals that 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 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 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. 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 June 30, 2017, our results of operations for the three and six months ended June 30, 2017 and 2016, and our cash flows for the six months ended June 30, 2017 and 2016. We derived our consolidated balance sheet as of December 31, 2016, from the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. Our results of operations for the three and six months ended June 30, 2017 and 2016, 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, 2016.

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 assets 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. NET INCOME PER LIMITED PARTNER INTEREST

We allocate our net income among our general partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income and any net income in excess of distributions to our limited partners, our general partner and the holder of the incentive distribution rights, or IDRs, according to the distribution formula for available cash as set forth in our partnership agreement. We allocate any distributions in excess of earnings for the period to our limited partners and general partner based on their respective proportionate ownership interests in us, as set forth in our partnership agreement after taking into account distributions to be paid with respect to the IDRs. The formula for distributing available cash as set forth in our partnership agreement is as follows:



Distribution Targets	Portion of Quarterly Distribution Per Unit	Percentage Distributed to Limited Partners	Percentage Distributed to General Partner (including IDRs) ⁽¹⁾
Minimum Quarterly Distribution	Up to $0.2875	98%	2%
First Target Distribution	> $0.2875 to $0.330625	98%	2%
Second Target Distribution	> $0.330625 to $0.359375	85%	15%
Third Target Distribution	> $0.359375 to $0.431250	75%	25%
Thereafter	Amounts above $0.431250	50%	50%

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

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



	Three Months Ended June 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⁾	$	6,014		$	2,138		$	33	$	194		$	8,379
Less: Distributable earnings ⁽²⁾	6,931			2,227			29		201			9,388
Distributions in excess of earnings	$	(917	)	$	(89	)	$	4	$	(7	)	$	(1,009	)
Weighted average units outstanding ⁽³⁾	17,329			6,278			93		461			24,161
Distributable earnings per unit ⁽⁴⁾	$	0.40		$	0.35		$	0.31
Overdistributed earnings per unit ⁽⁵⁾	(0.05		)	(0.01		)	0.04
Net income per limited partner unit (basic and diluted)	$	0.35		$	0.34		$	0.35


⁽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 $37 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 $0.34 per unit, or $1.36 per unit on an annualized basis. Amounts presented for each class of unit include a proportionate amount of the $388 thousand distributable 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.



	Three Months Ended June 30, 2016
	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⁾	$	3,206		$	1,893		$	32		$	104		$	5,235
Less: Distributable earnings ⁽²⁾	4,622			2,727			46			150			7,545
Distributions in excess of earnings	$	(1,416	)	$	(834	)	$	(14	)	$	(46	)	$	(2,310	)
Weighted average units outstanding ⁽³⁾	14,182			8,371			139			461			23,153
Distributable earnings per unit ⁽⁴⁾	$	0.33		$	0.33		$	0.33
Overdistributed earnings per unit ⁽⁵⁾	(0.10		)	(0.10		)	(0.10		)
Net income per limited partner unit (basic and diluted)	$	0.23		$	0.23		$	0.23


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period.

⁽²⁾

Represents the distributions paid for the period based upon the quarterly distribution of $0.315 per unit, or $1.26 per unit on an annualized basis. Amounts presented for each class of unit include a proportionate amount of the $252 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.



	Six Months Ended June 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⁾	$	9,422		$	3,784		$	59		$	312		$	13,577
Less: Distributable earnings ⁽²⁾	12,752			4,437			62			377			17,628
Distributions in excess of earnings	$	(3,330	)	$	(653	)	$	(3	)	$	(65	)	$	(4,051	)
Weighted average units outstanding ⁽³⁾	16,283			6,856			105			461			23,705
Distributable earnings per unit ⁽⁴⁾	$	0.78		$	0.65		$	0.59
Overdistributed earnings per unit ⁽⁵⁾	(0.20		)	(0.10		)	(0.03		)
Net income per limited partner unit (basic and diluted)	$	0.58		$	0.55		$	0.56


⁽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 $52 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the per unit distributions paid of $0.335 per unit for the three months ended March 31, 2017 and $0.34 payable for the three months ended June 30, 2017, representing a year-to-date distribution amount of $0.675 per unit. Amounts presented for each class of unit include a proportionate amount of the $397 thousand distributed and $388 thousand distributable 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.



	Six Months Ended June 30, 2016
	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⁾	$	4,361		$	2,829		$	48		$	147		$	7,385
Less: Distributable earnings ⁽²⁾	9,134			5,391			89			297			14,911
Distributions in excess of earnings	$	(4,773	)	$	(2,562	)	$	(41	)	$	(150	)	$	(7,526	)
Weighted average units outstanding ⁽³⁾	13,546			8,969			152			461			23,128
Distributable earnings per unit ⁽⁴⁾	$	0.67		$	0.60		$	0.59
Overdistributed earnings per unit ⁽⁵⁾	(0.35		)	(0.29		)	(0.27		)
Net income per limited partner unit (basic and diluted)	$	0.32		$	0.31		$	0.32


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period.

⁽²⁾

Represents the distributions paid of $0.3075 per unit with respect to the three months ended March 31, 2016, and $0.315 for the three months ended June 30, 2016, representing a year-to-date distribution amount of $0.6225 per unit. Amounts presented for each class of unit include a proportionate amount of the $499 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.

3. PROPERTY AND EQUIPMENT

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



	June 30, 2017			December 31, 2016			Estimated Useful Lives (Years)
	(in thousands)						Estimated Useful Lives (Years)
Land	$	10,775		$	9,636		N/A
Trackage and facilities	124,527			108,782			20
Pipeline	15,653			10,313			20
Equipment	12,531			8,234			5-10
Furniture	82			44			5
Total property and equipment	163,568			137,009
Accumulated depreciation	(17,764		)	(13,821		)
Construction in progress	2,822			2,514
Property and equipment, net	$	148,626		$	125,702

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.

On June 2, 2017, we acquired a 76-acre crude oil terminal in Stroud, Oklahoma, the Stroud terminal, for $22.8 million in cash, to facilitate rail-to-pipeline shipments of crude oil from our Hardisty terminal to Cushing, Oklahoma. The Stroud terminal includes unit train-capable unloading capacity of approximately 50,000 barrels per day, or Bpd, expandable to approximately 70,000 Bpd, as well as onsite tanks with 140,000 barrels of total capacity and a truck bay. Additionally, the terminal includes a 12-inch diameter, 17-mile pipeline with a direct connection to the crude oil storage hub located in Cushing, Oklahoma. Our acquisition of the Stroud terminal also included the purchase of approximately $1.4 million of crude oil used by the prior owner for line fill and tank bottoms and approximately $1.3 million of one-time costs we capitalized in connection with the transaction.

We accounted for the acquisition of the Stroud Terminal as an asset purchase, as a result of our early adoption of Financial Accounting Standards Board, or FASB, Accounting Standards Update No. 2017-01, or ASU 2017-01, which clarifies the definition of a business as set forth in Topic 805 of the FASB Accounting Standards Codification, or ASC.

4. INTANGIBLE ASSETS

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



	June 30, 2017			December 31, 2016
	(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	(20,434		)	(14,135		)
Other	(17		)	(12		)
Total accumulated amortization	(20,451		)	(14,147		)
Total intangible assets, net	$	105,615		$	111,919

Amortization expense associated with intangible assets totaled approximately $3.2 million for each of the three months ended June 30, 2017 and 2016, and $6.3 million and $6.4 million for the six months ended June 30, 2017 and 2016, respectively.

5. DEBT

We have a $400 million senior secured credit agreement, the Credit Agreement, previously comprised of a $300 million revolving credit facility, or the Revolving Credit Facility, and a $100 million term loan (borrowed in Canadian dollars), the Term Loan 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. In March 2017, we repaid the total amounts previously outstanding on the Term Loan Facility. As a result, our Revolving Credit Facility comprises the full $400 million capacity of our Credit Agreement, subject to the limits set forth therein. As of June 30, 2017, our outstanding indebtedness consists solely of amounts borrowed on our Revolving Credit Facility.

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. 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.

The average interest rate on our outstanding indebtedness was 3.68% and 3.66% at June 30, 2017 and December 31, 2016, 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 June 30, 2017, we were in compliance with the covenants set forth in our Credit Agreement.

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



	June 30, 2017		December 31, 2016
	(in millions)
Aggregate borrowing capacity under Credit Agreement	$	400.0	$	400.0
Less: Term Loan Facility amounts outstanding	—		10.1
Revolving Credit Facility amounts outstanding	206.0		213.0
Letters of credit outstanding	—		—
Available under Credit Agreement ⁽¹⁾	$	194.0	$	176.9

⁽¹⁾

Pursuant to the terms of our Credit Agreement, our borrowing capacity currently is limited to 5.0 times our trailing 12-month consolidated EBITDA for the quarter in which a material acquisition occurs and the two quarters following a material acquisition, as defined in our Credit Agreement, after which time the covenant returns to 4.5 times our trailing 12-month consolidated EBITDA. Our acquisition of the Stroud terminal is treated as a material acquisition under the terms of our Credit Agreement. As a result, the 5.0 times our trailing 12-month consolidated EBITDA covenant will be effective through December 31, 2017.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)
Interest expense on the Credit Agreement	$	2,298	$	2,318	$	4,690	$	4,286
Amortization of deferred financing costs	215		215		430		430
Total interest expense	$	2,513	$	2,533	$	5,120	$	4,716

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



	June 30, 2017			December 31, 2016
	(in thousands)
Term Loan Facility	$	—		$	10,128
Revolving Credit Facility	206,000			213,000
Less: Deferred financing costs, net	(1,804		)	(2,234		)
Total long-term debt, net	$	204,196		$	220,894

6. DEFERRED REVENUE

Our deferred revenue includes amounts we have received in cash from customers as payment for their minimum monthly commitment fees under take-or-pay contracts, where such payments exceed the charges implied by the customer’s actual throughput based on contractual rates set forth in our terminalling services agreements. We grant customers of our Hardisty terminal a credit for periods up to six months, which may be used to offset fees on throughput in excess of their minimum monthly commitments in future periods, to the extent capacity is available for the excess volume. We refer to these credits as make-up rights. We defer revenue associated with make-up rights until the earlier of when the throughput is utilized, the make-up rights expire, or when it is determined that the likelihood that the customer will utilize the make-up right is remote. A majority of our deferred revenue derived from the make-up rights provisions of our terminalling services agreements are denominated in Canadian dollars and translated into U.S. dollars at the exchange rate in effect at the end of the period. As a result, the balance of our deferred revenue may vary from period to period due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.

Our deferred revenues also include amounts collected in advance 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 our railcar leases that are associated with these deferred revenues, which we will recognize as expense concurrently with our recognition of the associated revenue.

The following table provides details of our deferred revenue with unrelated customers as reflected in our consolidated balance sheets as of the dates indicated:



	June 30, 2017		December 31, 2016
	(in thousands)
Customer prepayments, current portion ⁽¹⁾	$	1,895	$	3,705
Minimum monthly commitment fees	23,272		23,223
Total deferred revenue, current portion	$	25,167	$	26,928

Customer prepayments ⁽¹⁾	$	—	$	264
Total deferred revenue, net of current portion	$	—	$	264


⁽¹⁾	Represents amounts associated with lease payments received in advance from our Fleet services customers.

Refer to Note 9 — Transactions with Related Parties for a discussion of deferred revenues associated with related parties included in our consolidated balance sheets.

7. COLLABORATIVE ARRANGEMENT

We entered into a facilities connection agreement in 2014 with Gibson Energy Partnership, or 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 $5.4 million and $5.3 million of expenses for the three months ended June 30, 2017 and 2016, respectively, and $10.8 million and $10.1 million for the six months ended June 30, 2017 and 2016, respectively, which are presented as “Pipeline fees” in our consolidated statements of income. Additionally, at June 30, 2017 and December 31, 2016, we had prepaid pipeline fees of $7.1 million and $6.8 million, respectively, included in “Prepaid expenses” on our consolidated balance sheets, which we will recognize as expense concurrently with our recognition of revenue that we deferred in connection with our minimum monthly volume commitments.

8. NONCONSOLIDATED VARIABLE INTEREST ENTITIES

In 2014, we 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.

Prior to July 1, 2016, our activities with the VIEs were treated as related party transactions and disclosed in Note 9 – Transactions with Related Parties due to the managing member of the VIEs being a member of the board of directors of USD. The managing member subsequently transferred ownership and control of the companies to a party that is unaffiliated with USD or us. As a result, for periods following June 30, 2016, we no longer treat the VIEs as related parties.

The following table summarizes the total assets and liabilities between us and the VIEs as reflected in our consolidated balance sheets at June 30, 2017 and December 31, 2016, 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 revenues.



	June 30, 2017
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	28		$	—	$	—
Accounts payable	—		2		—
Deferred revenue, current portion	—		923		—
Deferred revenue, net of current portion	—		—		—
	$	28	$	925	$	—



	December 31, 2016
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	$	7	$	—	$	—
Accounts payable	—		3		—
Deferred revenue, current portion	—		1,297		—
Deferred revenue, net of current portion	—		264		—
	$	7	$	1,564	$	—

We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 2,613 railcars to the VIEs, but we have retained certain rights and obligations with respect to the servicing of these railcars.

During the quarter ended June 30, 2017, we provided no explicit or implicit financial or other support to these VIEs that were not previously contractually required.

9. 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 midstream 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 5,278,963 of our common units and all 6,278,127 of our subordinated units representing a combined 43.8% 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 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 June 30, 2017 and 2016, were $1.4 million and $1.4 million, respectively, and for the six months ended June 30, 2017 and 2016, were $2.8 million and $2.9 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At June 30, 2017 and December 31, 2016, 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.

From time to time, in the ordinary course of business, USD and its affiliates may receive vendor payments or other amounts due to us or our subsidiaries. In addition, we may make payments to vendors and other unrelated parties on behalf of USD and its affiliates for which they routinely reimburse us. We had a $0.1 million balance payable at June 30, 2017, related to these transactions included in “Accounts payable and accrued expenses— related party” and a $0.2 million balance receivable at December 31, 2016, associated with these transactions included in “Accounts receivable — related party” within our consolidated balance sheet.

Marketing Services Agreement

In connection with our purchase of the Stroud terminal, we entered into a Marketing Services Agreement, effective as of May 31, 2017, with USD Marketing LLC, or USDM, whereby we granted USDM the right to market the remaining capacity at the Stroud terminal in exchange for a nominal per barrel fee. USDM will fund any related capital costs associated with increasing the throughput or efficiency of the terminal to handle additional barrels. Upon expiration of our contract with the Stroud customer in June 2020, the same marketing rights will apply to throughput 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 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.

Variable Interest Entities

We entered into purchase, assignment and assumption agreements to assign payment and performance obligations for certain operating lease agreements, as well as customer fleet service payments related to these operating leases, with the VIEs. Prior to July 1, 2016, a member of the board of directors of USD exercised control over the VIEs as its managing member. Subsequent to June 30, 2016, the managing member transferred ownership of the VIEs to a party that is unaffiliated with USD or us. As a result, for periods following June 30, 2016, we no longer treat the VIEs as related parties. Refer to Note 8 – Nonconsolidated Variable Interest Entities for additional discussion and information regarding transactions with the VIEs subsequent to June 30, 2016.

For periods prior to July 1, 2016, our related party sales to the VIEs are included in the accompanying consolidated statements of operations as set forth in the following table for the indicated periods:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)
Fleet services — related party	$	—	$	405	$	—	$	810

Related Party Revenue and Deferred Revenue

We have agreements to provide USDM, a wholly-owned subsidiary of USDG, terminalling and fleet services with respect to our Hardisty terminal operations, which 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, and they control approximately 25 percent of the available monthly capacity of the Hardisty terminal. 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.

Our related party sales to USDM are presented in the following table for the indicated periods:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)
Terminalling services — related party	$	2,518	$	1,756	$	4,258	$	3,406
Fleet leases — related party	891		891		1,781		1,781
Fleet services — related party	279		279		558		558
Freight and other reimbursables — related party	—		—		1		—
	$	3,688	$	2,926	$	6,598	$	5,745

We had no significant receivables from USDM as of June 30, 2017 and December 31, 2016 recorded in “Accounts receivable — related party.” We had deferred revenue included in “Deferred revenue, current — related party” in our consolidated balance sheets associated with our terminalling and fleet services agreements with USDM for amounts we have collected from them for their minimum volume commitment fees and prepaid lease amounts as follows for the indicated periods:



	June 30, 2017		December 31, 2016
	(in thousands)
Customer prepayments, current portion ⁽¹⁾	$	410	$	390
Minimum monthly commitment fees	5,071		3,902
Total deferred revenue, current portion	$	5,481	$	4,292


⁽¹⁾	Represents amounts associated with lease payments received in advance.

Cash Distributions

During the six months ended June 30, 2017, 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.



Distribution Declaration Date	Record Date	Distribution Payment Date	Amount Paid to USDG		Amount Paid to USD Partners GP LLC
			(in thousands)
February 1, 2017	February 13, 2017	February 17, 2017	$	3,814	$	152
April 27, 2017	May 8, 2017	May 12, 2017	3,872		170
			$	7,686	$	322

Transition Services Agreement

In connection with our acquisition of the Casper terminal in November 2015, we entered into a transition services agreement with Cogent Energy Solutions, LLC, or Cogent, pursuant to which Cogent provided certain accounting, administrative, customer support and information technology support services to the Casper terminal for three months following the November 17, 2015, closing date, while we transitioned such services to our management. Two officers of an affiliate of our general partner are the principal owners of Cogent. As a result, these officers were considered to be beneficiaries of this agreement. Pursuant to the terms of this agreement, we incurred approximately $52 thousand of expenses for the three and six months ended June 30, 2016. Cogent subsequently distributed to their partners the common units we issued to them in connection with our acquisition of the Casper terminal and is no longer considered a related party.

10. 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.

In connection with the railcar services we provide, we regularly incur railcar cleanup and repair costs upon our return of these railcars to the lessors. We typically pass such costs on to our customers pursuant to the terms of our lease agreements with them. A legacy customer associated with a terminal sold by USD prior to our IPO has returned 265 railcars to us, all of which the lessors claim require additional cleaning and repair from alleged corrosion. We are currently in discussions with the lessors and our customer regarding the validity of these additional costs. We believe that our customer will ultimately be responsible for any costs associated with these returns, and USD has agreed to indemnify us to the extent that we are unable to recover any such costs from our customer.

11. 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 various grades of crude oil into 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 long-term, take-or-pay contracts. Corporate activities are not considered a reportable segment, but are included to present corporate and financing transactions 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, changes in restricted cash, interest, income taxes, foreign currency transaction gains and losses, adjustments related to deferred revenue associated with minimum monthly commitment fees and other items which do not affect the underlying cash flows produced by our businesses.

The following tables summarize our reportable segment data:



	Three Months Ended June 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	21,977		$	—	$	—		$	21,977
Terminalling services — related party	2,518			—		—			2,518
Railroad incentives	6			—		—			6
Fleet leases	—			643		—			643
Fleet leases — related party	—			891		—			891
Fleet services	—			467		—			467
Fleet services — related party	—			279		—			279
Freight and other reimbursables	89			119		—			208
Freight and other reimbursables — related party	—			—		—			—
Total revenues	24,590			2,399		—			26,989
Operating costs
Subcontracted rail services	1,795			—		—			1,795
Pipeline fees	5,369			—		—			5,369
Fleet leases	—			1,534		—			1,534
Freight and other reimbursables	89			119		—			208
Operating and maintenance	500			94		—			594
Selling, general and administrative	1,185			188		2,385			3,758
Depreciation and amortization	4,969			—		—			4,969
Total operating costs	13,907			1,935		2,385			18,227
Operating income (loss)	10,683			464		(2,385		)	8,762
Interest expense	—			—		2,513			2,513
Loss associated with derivative instruments	401			—		—			401
Foreign currency transaction loss (gain)	(13		)	2		(89		)	(100		)
Other expense, net	3			—		—			3
Provision for (benefit from) income taxes	(2,423		)	181		(192		)	(2,434		)
Net income (loss)	$	12,715		$	281	$	(4,617	)	$	8,379



	Three Months Ended June 30, 2016
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	23,459		$	—		$	—		$	23,459
Terminalling services — related party	1,756			—			—			1,756
Railroad incentives	22			—			—			22
Fleet leases	—			647			—			647
Fleet leases — related party	—			891			—			891
Fleet services	—			69			—			69
Fleet services — related party	—			684			—			684
Freight and other reimbursables	19			331			—			350
Freight and other reimbursables — related party	—			—			—			—
Total revenues	25,256			2,622			—			27,878
Operating costs
Subcontracted rail services	2,026			—			—			2,026
Pipeline fees	5,338			—			—			5,338
Fleet leases	—			1,538			—			1,538
Freight and other reimbursables	19			331			—			350
Operating and maintenance	692			91			—			783
Selling, general and administrative	1,056			207			2,249			3,512
Depreciation and amortization	4,914			—			—			4,914
Total operating costs	14,045			2,167			2,249			18,461
Operating income (loss)	11,211			455			(2,249		)	9,417
Interest expense	352			—			2,181			2,533
Gain associated with derivative instruments	(253		)	—			—			(253		)
Foreign currency transaction loss (gain)	5			(20		)	—			(15		)
Other expense, net	—			—			—			—
Provision for (benefit from) income taxes	1,948			(32		)	1			1,917
Net income (loss)	$	9,159		$	507		$	(4,431	)	$	5,235



	Six Months Ended June 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	45,536		$	—	$	—		$	45,536
Terminalling services — related party	4,258			—		—			4,258
Railroad incentives	21			—		—			21
Fleet leases	—			1,286		—			1,286
Fleet leases — related party	—			1,781		—			1,781
Fleet services	—			935		—			935
Fleet services — related party	—			558		—			558
Freight and other reimbursables	110			255		—			365
Freight and other reimbursables — related party	—			1		—			1
Total revenues	49,925			4,816		—			54,741
Operating costs
Subcontracted rail services	3,808			—		—			3,808
Pipeline fees	10,786			—		—			10,786
Fleet leases	—			3,067		—			3,067
Freight and other reimbursables	110			256		—			366
Operating and maintenance	1,111			190		—			1,301
Selling, general and administrative	2,400			484		4,621			7,505
Depreciation and amortization	9,910			—		—			9,910
Total operating costs	28,125			3,997		4,621			36,743
Operating income (loss)	21,800			819		(4,621		)	17,998
Interest expense	170			—		4,950			5,120
Loss associated with derivative instruments	612			—		—			612
Foreign currency transaction loss (gain)	(13		)	2		(59		)	(70		)
Other expense, net	8			—		—			8
Provision for (benefit from) income taxes	(1,418		)	315		(146		)	(1,249		)
Net income (loss)	$	22,441		$	502	$	(9,366	)	$	13,577
Goodwill	$	33,589		$	—	$	—		$	33,589
Total assets	$	315,258		$	3,018	$	2,326		$	320,602
Capital expenditures	$	25,773		$	—	$	—		$	25,773



	Six Months Ended June 30, 2016
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	45,482		$	—		$	—		$	45,482
Terminalling services — related party	3,406			—			—			3,406
Railroad incentives	37			—			—			37
Fleet leases	—			1,290			—			1,290
Fleet leases — related party	—			1,781			—			1,781
Fleet services	—			138			—			138
Fleet services — related party	—			1,368			—			1,368
Freight and other reimbursables	19			714			—			733
Freight and other reimbursables — related party	—			—			—			—
Total revenues	48,944			5,291			—			54,235
Operating costs
Subcontracted rail services	4,069			—			—			4,069
Pipeline fees	10,052			—			—			10,052
Fleet leases	—			3,071			—			3,071
Freight and other reimbursables	19			714			—			733
Operating and maintenance	1,507			146			—			1,653
Selling, general and administrative	2,290			401			5,207			7,898
Depreciation and amortization	9,819			—			—			9,819
Total operating costs	27,756			4,332			5,207			37,295
Operating income (loss)	21,188			959			(5,207		)	16,940
Interest expense	682			—			4,034			4,716
Loss associated with derivative instruments	1,270			—			—			1,270
Foreign currency transaction gain	(75		)	(70		)	—			(145		)
Other expense, net	—			—			—			—
Provision for (benefit from) income taxes	3,731			(18		)	1			3,714
Net income (loss)	$	15,580		$	1,047		$	(9,242	)	$	7,385
Goodwill	$	33,970		$	—		$	—		$	33,970
Total assets	$	311,394		$	5,886		$	3,183		$	320,463
Capital expenditures	$	246		$	—		$	—		$	246

Segment Adjusted EBITDA

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	15,811		$	17,095		$	32,248		$	33,230
Fleet services	464			455			819			959
Corporate activities ⁽¹⁾	(1,167		)	(1,280		)	(2,605		)	(3,510		)
Total Adjusted EBITDA	15,108			16,270			30,462			30,679
Add (deduct):
Amortization of deferred financing costs	215			215			430			430
Deferred income taxes	249			(50		)	307			(96		)
Changes in accounts receivable and other assets	(3,180		)	(467		)	(1,353		)	1,507
Changes in accounts payable and accrued expenses	(1,486		)	(1,105		)	(1,086		)	(1,937		)
Changes in deferred revenue and other liabilities	(1,400		)	1,557			(2,520		)	2,100
Change in restricted cash	(209		)	1,793			(230		)	(633		)
Interest expense, net	(2,513		)	(2,533		)	(5,116		)	(4,716		)
Benefit from (provision for) income taxes	2,434			(1,917		)	1,249			(3,714		)
Foreign currency transaction gain ⁽²⁾	100			15			70			145
Deferred revenue associated with minimum monthly commitment fees ⁽³⁾	(62		)	(424		)	(142		)	(1,187		)
Net cash provided by operating activities	$	9,256		$	13,354		$	22,071		$	22,578


⁽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 deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to our customers. Amounts presented are net of: (a) the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue; (b) revenue recognized in the current period that was previously deferred; and (c) expense recognized for previously prepaid Gibson pipeline fees, which correspond with the revenue recognized that was previously deferred. Refer to Note 6 - Deferred Revenues for additional discussion of deferred revenue.

12. 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 upon our estimated annual effective federal income tax rate of 34%, as applied to USD Rail LP’s taxable income of $0.8 million and $1.1 million for the three and six months ended June 30, 2017, respectively. We recorded a provision for U.S. federal income tax with respect to these periods utilizing net operating loss carryforwards to offset a portion of our taxable income. For the three and six months ended June 30, 2016, we had losses of $0.9 million and $1.2 million, respectively, and as a result of these losses, we did not record a provision for U.S. federal income tax with respect to these periods.

Foreign Income Taxes

Our Canadian operations are conducted through entities that are subject to Canadian federal and provincial income taxes. We computed the current income tax expense associated with our Canadian operations using the combined federal and provincial income tax rate of 27% applied to the pretax book income of our Canadian operations for the three and six months ended June 30, 2017 and 2016. The combined rate was also used to compute deferred income tax expense, which is the result of temporary differences that are expected to reverse in the future.

The 2017 income tax expense of our Canadian operations includes a reduction to our estimate for 2016 income tax expense resulting from refunds of approximately $2.6 million (C$3.4 million) we determined in connection with the preparation of our Canadian federal and provincial income tax returns for 2016 that we filed in June 2017. In 2016, we adopted a methodology for determining the return attributable to our Canadian subsidiaries based upon completion of a study we initially commissioned in 2015, which modifies the amount of Canadian federal and provincial income taxes to which our Canadian operations are subject. We calculated our 2017 and 2016 income tax provisions for our Canadian operations utilizing this methodology.

Combined Effective Income Tax Rate

We determined our 2017 income tax expense based upon our estimated annual effective income tax rate of approximately 27% on a consolidated basis for fiscal year 2017, which rate is attributable to the multiple domestic and foreign tax jurisdictions to which we are subject.



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Current income tax expense (benefit):
U.S. federal income tax	$	275		$	—		$	373		$	—
Benefit of U.S. federal operating loss carryforward	(158		)	—			(256		)	—
State income tax expense (benefit)	(172		)	(7		)	(109		)	30
Canadian federal and provincial income taxes expense (benefit)	(2,628		)	1,974			(1,564		)	3,780
Total current income tax expense (benefit)	(2,683		)	1,967			(1,556		)	3,810
Deferred income tax expense (benefit):
U.S. federal income tax	53			—			174			—
Canadian federal and provincial income taxes expense (benefit)	196			(50		)	133			(96		)
Total change in deferred income tax expense (benefit)	249			(50		)	307			(96		)
Provision for (benefit from) income taxes	$	(2,434	)	$	1,917		$	(1,249	)	$	3,714

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Income tax expense at the U.S. federal statutory rate	$	2,022		$	2,432		$	4,192		$	3,774
Amount attributable to partnership not subject to income tax	(4,873		)	215			(5,714		)	1,159
Foreign income tax rate differential	570			(515		)	365			(959		)
Other	12			(94		)	11			(62		)
State income tax expense (benefit) ⁽¹⁾	(177		)	(7		)	(118		)	30
Change in valuation allowance	12			(114		)	15			(228		)
Provision for (benefit from) income taxes	$	(2,434	)	$	1,917		$	(1,249	)	$	3,714


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

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



	June 30, 2017
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Deferred revenues	$	—		$	—		$	—
Capital loss carryforwards	—			453			453
Operating loss carryforwards	—			—			—
Deferred income tax liabilities
Unbilled revenue	—			(270		)	(270		)
Prepaid expenses	(419		)	—			(419		)
Property and equipment	—			(464		)	(464		)
Valuation allowance	—			(453		)	(453		)
Deferred income tax liability, net	$	(419	)	$	(734	)	$	(1,153	)



	December 31, 2016
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Deferred revenues	$	89		$	—		$	89
Capital loss carryforwards	—			438			438
Operating loss carryforwards	257			—			257
Deferred income tax liabilities
Prepaid expenses	(592		)	—			(592		)
Property and equipment	—			(577		)	(577		)
Valuation allowance	—			(438		)	(438		)
Deferred income tax liability, net	$	(246	)	$	(577	)	$	(823	)

We had no available U.S. federal loss carryforward remaining as of June 30, 2017, and approximately $0.8 million as of December 31, 2016. Our available Canadian loss carryforward was approximately $4.5 million and $4.4 million as of June 30, 2017 and December 31, 2016, respectively, which will begin expiring in 2033.

We are subject to examination by the taxing authorities for the years ended December 31, 2016, 2015 and 2014. USD has agreed to indemnify us for all federal, state and local tax liabilities for periods preceding the closing date of our initial public offering. We did not have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of June 30, 2017 and December 31, 2016.

13. 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 foreign currency exchange rates, particularly with respect to the U.S. dollar and the Canadian dollar. At June 30, 2017 and December 31, 2016, we did not employ any derivative financial instruments to manage our exposure to fluctuations in interest rates, although we may use derivative financial instruments, including swaps, options and other financial instruments with similar characteristics to manage this exposure in the future.

Foreign Currency Derivatives

We derive a significant portion of our cash flows from our Hardisty terminal operations in the province of Alberta, Canada. These cash flows 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. All of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into for speculative purposes.

In 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 fixes the exchange rate we will receive for each Canadian dollar we sell to the counterparty. One of these forward contracts will settle at the end of each fiscal quarter during 2017 and secures an exchange rate where a Canadian dollar is exchanged for an amount between 0.7804 and 0.7809 U.S. dollars.

In June 2015, we entered into four separate collar arrangements with an aggregate notional value of C$32.0 million, which settled at the end of each fiscal quarter during 2016, each having a notional value ranging between C$7.9 million and C$8.1 million. These derivative contracts were executed to secure cash flows totaling C$32.0 million at an exchange rate range where a Canadian dollar is exchanged for an amount between 0.84 and 0.86 U.S. dollars.

Commodity Derivatives

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. We intend to sell this crude oil prior to the end of 2017. Due to our long position with respect to crude oil, fluctuations in crude oil prices could affect our results of operations, cash flows and financial positions. In order to mitigate this risk, we have entered into commodity swaps to fix the price we will receive upon our sale of the crude oil.

In June 2017, we entered into two separate fixed-for-floating swap contracts with an aggregate notional amount of 31,778 barrels, or bbl, to manage our exposure to fluctuating crude oil prices. Each swap contract effectively fixes the price we will receive upon our delivery of the crude oil. The first contract for 18,395 bbl will settle in July 2017 at $47.20 per barrel and the second for 13,383 bbl will settle in October 2017 at $47.70 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:



	June 30, 2017		December 31, 2016
	(in thousands)
Other current assets	$	165	$	1,167

We have not designated our derivative financial instruments as hedges of our commodity or foreign currency exposures. As a result, changes in the fair value of these derivatives are recorded as “Loss (gain) associated with derivative instruments” in our consolidated statements of income. The gains or losses associated with changes in the fair value of our derivative contracts do not affect our cash flows until the underlying contract is settled by making or receiving a payment to or from the counterparty. In connection with our derivative activities, we recognized the following amounts during the periods presented:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
	(in thousands)
Loss (gain) associated with derivative instruments	$	401	$	(253	)	$	612	$	1,270

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 tables present summarized information about the fair values of our outstanding foreign currency contracts:



	At June 30, 2017						At December 31, 2016
	Notional (C$)		Forward Rate ⁽¹⁾	Market Price⁽¹⁾	Fair Value		Fair Value
					(in thousands)
Forward contracts maturing in 2017
March 31, 2017	C$	8,300,000	0.7804	—	$	—	$	299
June 30, 2017	C$	8,400,000	0.7805	—	—		296
September 29, 2017	C$	8,400,000	0.7807	0.7725	69		290
December 29, 2017	C$	8,400,000	0.7809	0.7732	65		282
Total					$	134	$	1,167


⁽¹⁾	Forward rates and market prices are denoted in amounts where a Canadian dollar is exchanged for the indicated amount of U.S. dollars. The forward rate represents the rate we will receive upon settlement. The market price represents the rate we would expect to pay had the contract been settled on June 30, 2017.



	At June 30, 2017
	Notional	Market Price ⁽¹⁾		Fixed Price ⁽²⁾		Fair Value
	(in Bbls)					(in thousands)
Commodity swaps maturing in 2017
July 2017	18,395	$	46.13	$	47.20	$	20
October 2017	13,383	$	46.86	$	47.70	11
	31,778					$	31


⁽¹⁾	The market price represents the price we would pay to purchase one barrel of crude oil of the grade specified for the settlement date as set forth in the derivative contract as of June 30, 2017.


⁽²⁾	The fixed price represents the fixed price we will receive upon our sale of one barrel of crude oil of the grade specified for the settlement date as set forth in the derivative contract.

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. We did not have any liabilities associated with our derivative contracts at June 30, 2017 or December 31, 2016, that were offset against the asset balances for the respective periods.

14. PARTNERS’ CAPITAL

Our common units and subordinated units represent limited partner interests in us. The holders of our 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 in respect of our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and, as a result, are considered participating securities. 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 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 and will be no more than 1.75 for the third vesting tranche and 2.00 for the fourth and final vesting tranche. In February 2017, pursuant to the terms set forth in our partnership agreement, the second vesting tranche of 46,250 Class A units vested. We determined that, upon conversion, each vested Class A unit would receive one and one-half (1.50) common units based upon our distributions paid for the four preceding quarters. As a result, 46,250 Class A units were converted into 69,375 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. A 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 2017, pursuant to the terms set forth in our partnership agreement, we converted the second 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 2014 Long-Term Incentive Plan, which we refer to as the 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 269,286 vested during the first half of 2017, of which 190,016 were converted into our common units after 79,270 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 15 - 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 is determined by our general partner.

In June 2017, we completed an underwritten public offering of 3,000,000 common units that we used to repay a portion of the amounts outstanding on our revolving credit facility, including amounts we borrowed to fund our acquisition of the Stroud terminal.

The following table presents the net proceeds from our common unit issuances:



	Number of Common Units Issued	Public Offering Price per Common Unit		Net Proceeds to the Partnership ⁽¹⁾
				(in millions)

June 7, 2017 Issuance	3,000,000	$	11.60	$	33.7

⁽¹⁾Net of underwriter’s fees and discounts, commissions and issuance costs.

15. UNIT BASED COMPENSATION

Class A units

Our Class A units vest over a four year period if established distribution target thresholds are met each year of the four year vesting period. In February 2017, pursuant to the terms set forth in our partnership agreement, the second vesting tranche of 46,250 Class A units vested based upon our distributions paid for the four preceding quarters and were converted on a basis of one and one-half common units for each class A unit. As a result, we converted 46,250 Class A units into 69,375 common units. The grant date average fair value of all Class A units was $25.71 per unit at June 30, 2017 and 2016.



	Six Months Ended June 30,
	2017		2016
Class A units outstanding at beginning of period	138,750		185,000
Vested	(46,250	)	(46,250	)
Class A units outstanding at end of period	92,500		138,750

We recognized compensation expense with regard to our Class A units of approximately $0.1 million and $0.2 million for the three months ended June 30, 2017 and 2016, respectively, and $0.2 million and $0.5 million for the six months ended June 30, 2017 and 2016, respectively, which cost is included in “Selling, general and administrative” in our consolidated statements of income. We did not have any forfeitures during the three and six months ended June 30, 2017 or 2016. 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 it is determined that the Class A units are not expected to vest. For the three and six months ended June 30, 2017 and 2016, we did not recognize any compensation expense for distributions paid on Class A units that are not expected to vest.

Long-term Incentive Plan

In 2017 and 2016, the board of directors of our general partner, acting in its capacity as our general partner, approved the grant of 687,099 and 576,373 Phantom Units, respectively, to directors and employees of our general partner and its affiliates under our LTIP. The total number of our common units initially authorized for issuance under the LTIP was 1,654,167, of which 132,232 remained available at June 30, 2017. The Phantom Units are subject to all of the terms and conditions of the 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 determined based on an allocation formula which included a percentage multiplier of the grantee’s base salary, among other factors, converted to a number of units based on the closing price of one of our common units preceding the grant date, as 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 typically vest over a one year period following the grant date.

The following tables present our Equity-classified Phantom Unit award activity:



	Number of Director and Independent Consultant Units		Number of Employee Units		Weighted-Average Grant Date Fair Value Per Unit
Phantom Unit awards at December 31, 2016	64,830		730,808		$	8.51
Granted	24,999		633,955		$	12.80
Vested	(64,830	)	(204,456	)	$	8.47
Forfeited	—		(2,660	)	$	11.20
Phantom Unit awards at June 30, 2017	24,999		1,157,647		$	10.90



	Number of Director and Independent Consultant Units		Number of Employee Units		Weighted-Average Grant Date Fair Value Per Unit
Phantom Unit awards at December 31, 2015	24,045		349,976		$	12.75
Granted	64,830		471,412		$	6.39
Vested	(20,442	)	(87,500	)	$	12.79
Phantom Unit awards at June 30, 2016	68,433		733,888		$	8.50

The following tables present our Liability-classified Phantom Unit award activity:



	Number of Director and Independent Consultant Units		Number of Employee Units	Weighted-Average Grant Date Fair Value Per 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 June 30, 2017	8,333		41,427	$	11.15



	Number of Director and Independent Consultant Units		Number of Employee Units	Weighted-Average Grant Date Fair Value Per Unit
Phantom Unit awards at December 31, 2015	10,256		13,276	$	12.78
Granted	21,610		17,021	$	6.39
Vested	(10,256	)	—	$	12.78
Phantom Unit awards at June 30, 2016	21,610		30,297	$	8.02

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 June 30, 2017 and 2016, we recognized approximately $1.1 million and $0.7 million, respectively, of compensation expense associated with outstanding Phantom Units, and for the six months ended June 30, 2017 and 2016, we recognized approximately $1.8 million and $1.2 million, respectively. As of June 30, 2017, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $11.8 million, which we expect to recognize over a weighted average period of 3.07 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 granted to them under the Award Agreements as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)
Equity-classified Phantom Units ⁽¹⁾	$	388	$	247	$	651	$	360
Liability-classified Phantom Units	17		16		31		23
Total	$	405	$	263	$	682	$	383


⁽¹⁾	We reclassified $3 thousand for the three and six months ended June 30, 2017, to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited. We had no forfeitures for the three and six months ended June 30, 2016.

16. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended June 30,
	2017		2016
	(in thousands)
Cash paid for income taxes	$	1,414	$	3,196
Cash paid for interest	$	4,937	$	3,987

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



	Six Months Ended June 30,
	2017		2016
	(in thousands)
Loss associated with disposal of assets	$	18	$	—
Amortization of deferred financing costs	$	430	$	430
Deferred income taxes	$	307	$	(96	)
	$	755	$	334

17. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Intangibles — Goodwill and Other

In January 2017, the FASB issued Accounting Standards Update No. 2017-04, or ASU 2017-04, which amends ASC Topic 350 to modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will 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. An entity should 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 should not 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 our adoption of this standard to have a material impact on our consolidated financial statements.

Restricted Cash

In November 2016, the FASB issued Accounting Standards Update No. 2016-18, or ASU 2016-18, which amends 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 will be 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.

The pronouncement is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and is required to be applied retrospectively for all financial statements presented, with early adoption permitted. We do not expect to adopt this standard early, nor do we expect our adoption of this standard to have a material impact on our consolidated financial statements, other than the presentation of cash and cash equivalents within our consolidated statements of cash flows.

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.

We cannot reasonably estimate the impact our adoption of ASU 2016-02 will currently have on our consolidated financial statements. 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 will involve 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 recently initiated steps to identify, accumulate and categorize our lease agreements into homogeneous groups to evaluate the particular terms for each type of agreements in relation to the requirements of ASU 2016-02 to determine the accounting impact, commonly referred to as an “Impact Assessment.” Once we have determined the impact ASU 2016-02 will have on our current accounting for each particular type of lease, we will develop accounting policies and internal control processes and initiate other steps to implement ASU 2016-02. We do not currently expect to early adopt the provisions of this standard.

Revenue from Contracts with Customers

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, or ASU 2014-09, that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. ASU 2014-09 is effective for annual and interim periods beginning on or after December 15, 2017, and may be applied on either a full or modified retrospective basis. 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 guidance, all of which will be effective upon adoption.

We have performed an initial assessment of the impact our adoption of ASU 2014-09 is expected to have on our current accounting policies, which remains subject to revision following the review and approval of our management. Our implementation of these policies will next require us to develop appropriate financial models to permit quantifying the impact our application of ASU 2014-09 will have on our previously issued financial statements. Additionally, our implementation of ASU 2014-09 will require training and educating our workforce and the investment community regarding the financial statement impact that application of the standard will have based upon the terms of our existing contracts and any new contracts we may execute in the future. Our evaluation and modification of existing accounting policies is ongoing, but nearing completion.

We currently expect to adopt ASU 2014-09 by applying the full retrospective transition method. The most significant policy revision we have identified to date relates to our accounting for the make-up rights provisions granted to customers of our Hardisty terminal. Under our current policy, we defer revenue associated with the make-up rights provisions until the earlier of when the throughput is utilized, the make-up rights expire, or when we determine the likelihood that the customer will utilize the make-up right is remote. Our revised revenue policy will require us to assess the value of the make-up right option based upon the likelihood of exercise and the expected amount to be received from the option exercise to determine the amount of revenue to defer. For example, if we consider the make-up right option unlikely to be exercised, we would attribute no value to the option and apply 100% breakage, resulting in the recognition of all the revenue. We have identified other elements within our consolidated financial statements that are likely to be affected by our policy revisions for assessing the value of make-up right provisions granted to customers of our Hardisty terminal. However, we continue to evaluate the impact our adoption of ASU 2014-09 may have on other elements within our consolidated financial statements. We cannot currently quantify with sufficient accuracy the impact that our adoption will have on each of the elements we expect to be affected within our consolidated financial statements.

The following discussion addresses the primary items within our financial statements we expect to be affected by our application of the requirements of ASU 2014-09, based upon modifications of our accounting policies, which have not yet been finalized. The discussion focuses on the impact we expect ASU 2014-09 to have on each of these items as compared with the amounts we have historically presented as a result of our application of currently accepted accounting standards associated with revenue. Once ASU 2014-09 is adopted and presented on a full retrospective basis, we anticipate the variances between periods for each of the items discussed will not be significantly different than the historical trends in each of these items.

Terminalling Services Revenue and Deferred Revenue — We expect the terminalling services revenue of our Hardisty terminal operations to increase by a portion of the amounts previously deferred in connection with the payments we receive from our customers for their minimum monthly volume commitments. 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 right options has been 100%, which could result in our recognizing a portion, or all of the previously deferred amounts as revenue upon our adoption of ASU 2014-09. Breakage rates will be regularly evaluated and modified as necessary to reflect our current expectations and experience.

Pipeline Fees and Prepaid Expenses — We expect our pipeline fees to increase by a portion of the amounts we have paid to Gibson and historically recorded as prepaid pipeline fees in connection with the revenue we have collected from customers of our Hardisty terminal for minimum monthly commitment fees for which we have deferred recognition. We have historically recognized these prepaid pipeline fees as expense concurrently with the 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 expected recognition of a portion of the previously deferred revenue, we expect to concurrently recognize a comparable portion of the prepaid pipeline fees as expense in connection with our adoption of ASU 2014-09.

Provision for Income Taxes and Non-current Deferred Income Tax Liability — As a result of the anticipated increases in “Terminalling services revenue” and “Pipeline fees” as discussed above, we expect our provision for income taxes and the related non-current deferred income tax liability to be affected by the change resulting from the expected increase in “Income (loss) from continuing operations before provision for income taxes.”

Other Comprehensive Income - Foreign Currency Translation and Accumulated Other Comprehensive Income — Our translation of the foregoing items within our consolidated income statements and balance sheets will also result in changes to the amounts reported in our consolidated statements of comprehensive income for “Other comprehensive income – foreign currency translation” and the related amount for “Accumulated other comprehensive income (loss)” 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.

Cash Flows From Operating Activities — We do not expect our adoption of ASU 2014-09 to affect the amount we report as cash flow from operating activities, as our adoption of this standard does not affect cash flow. However, we expect the components that comprise “Net cash provided by operating activities” within our Consolidated Statements of Cash Flows will change to reflect the changes presented in the income statement and balance sheet items discussed above.

18. SUBSEQUENT EVENTS

Distribution to Partners

On July 27, 2017, the board of directors of USD Partners GP LLC, acting in its capacity as our general partner, declared a quarterly cash distribution payable of $0.34 per unit, or $1.36 per unit on an annualized basis, for the three months ended June 30, 2017. The distribution represents an increase of $0.005 per unit, or 1.5% over the prior quarter distribution per unit, and is 18.3% over our minimum quarterly distribution per unit. The distribution will be paid on August 11, 2017, to unitholders of record at the close of business on August 7, 2017. The distribution will include payment of $4.8 million to our public common unitholders, $28 thousand to the Class A unitholders, an aggregate of $3.9 million to USDG as a holder of our common units and the sole owner of our subordinated units and $194 thousand to USD Partners GP LLC for its general partner interest and as holder of the IDR.

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 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, 2016. 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, 2016. 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 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 and refiners. Our principal assets include a network of crude terminals that 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 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 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. 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, which owns 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 solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the Permian Basin and the U.S. Gulf Coast. Among other projects, USDG is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with substantial tank storage capacity, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities.

Recent Developments

Stroud Terminal Acquisition

On June 2, 2017, we acquired a 76-acre crude oil terminal in Stroud, Oklahoma, the Stroud terminal, for approximately $22.8 million in cash. We acquired the Stroud terminal to facilitate rail-to-pipeline shipments of crude oil from our Hardisty terminal to Cushing, Oklahoma. The Stroud terminal includes unit train-capable unloading capacity of approximately 50,000 barrels per day, or Bpd, expandable to approximately 70,000 Bpd, as well as onsite tanks with 140,000 barrels of total capacity and a truck bay. Additionally, the terminal includes a 12-inch diameter, 17-mile pipeline with a direct connection to the crude oil storage hub located in Cushing, Oklahoma. We also obtained a lease for 300,000 barrels of crude oil tank storage at the Cushing hub to receive outbound shipments of crude oil from the Stroud terminal. Inbound product is delivered by the Stillwater Central Rail, which handles deliveries from both the BNSF and the Union Pacific railways.

In connection with this acquisition, we also purchased approximately $1.4 million and expect to purchase another $1.2 million of crude oil used by the prior owner for line fill and tank bottoms, all of which we sold in July or expect to sell in the near term. Additionally, we capitalized approximately $1.3 million of one-time transaction costs. During the third quarter of 2017, we expect to incur approximately $1.2 million of growth capital expenditures to retrofit the Stroud terminal to handle heavy grades of Canadian crude oil.

Concurrent with the Stroud acquisition, we entered into a new multi-year, take-or-pay terminalling services agreement with an investment grade rated multi-national energy company, the Stroud customer, for the use of approximately 50% of the available capacity at the Stroud terminal. The term of this agreement is scheduled to begin on October 1, 2017, and to conclude on June 30, 2020, unless otherwise renewed or extended. To facilitate the origination of barrels from our Hardisty terminal to be shipped to the Stroud terminal, an affiliate of our general partner assumed the rights and obligations for additional capacity at our Hardisty terminal from another customer, effective June 1, 2017, and entered into an agreement with the Stroud customer for the aggregate loading capacity held by our affiliate and our former customer. This transaction effectively extends the contracted term for approximately 25% of the Hardisty terminal’s capacity to June 2020.

We believe the Stroud terminal represents one of the most advantaged rail destinations for Western Canadian crude oil given established connectivity from Cushing to multiple refining centers across the U.S., including underutilized pipelines to major refining centers along the Gulf Coast. As such, we expect customers to achieve a lower all-in transportation cost relative to railing directly to destinations along the Gulf Coast. Rail also generally provides greater ability to preserve the specific quality of a customer’s product relative to pipelines, providing value to a producer or refiner.

Equity Offering

On June 7, 2017, we issued 3,000,000 common units in an underwritten public offering at a public offering price of $11.60 per unit. We received proceeds, net of offering costs, of approximately $33.7 million, which we used to repay amounts outstanding under our Revolving Credit Facility, including amounts used to fund our purchase of the Stroud terminal.

San Antonio Terminal

We have historically operated a unit train-capable ethanol destination terminal in San Antonio, Texas, that we ceased operating in the second quarter of 2017 following the conclusion of our customer’s agreement with us. We are exploring opportunities to provide ethanol terminalling services to other potential customers in the San Antonio market from this existing location or other locations.

Customer Contract Expirations and Renewals

A customer of our Casper terminal, whose existing terminalling services agreement with us expires in the third quarter of 2017, has indicated that they do not intend to renew their agreement with us. We cannot fully estimate the impact the expiration of this contract will have on our financial results, but this contract expiration could result in the potential impairment of amounts we have recorded as goodwill, as well as the intangible assets associated with our customer service agreements. The expiring agreement contributed approximately $15 million to our “Terminalling services” revenue and approximately $12 million of Adjusted EBITDA during the twelve months ended June 30, 2017. We continue to actively pursue commercial arrangements with other existing and potential new customers for the provision of terminalling services to utilize the available capacity. However, we cannot make any assurances regarding the outcome or timing of these endeavors.

As discussed in this Report, we continue to expect Western Canada crude oil production, including announced additions to oil sands production capacity, to exceed near-term pipeline takeaway capacity, providing a meaningful opportunity to meet upcoming takeaway needs with our strategically-positioned and scalable assets, particularly given current industry headwinds for new infrastructure projects.

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 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 transportation costs from supply areas to demand centers.

In March 2017, an incident at the Syncrude Mildred Lake Upgrader facility resulted in a major unplanned outage and accelerated the timing of planned turnaround activities and maintenance work. This decreased the supply of synthetic crude oil available to the market during the second quarter of 2017. In turn, producers who mix synthetic crude oil with bitumen were forced to reduce their production of heavy blended crude oil. As a result, near-term spreads between WCS and other benchmarks have tightened. Suncor Energy, the majority owner of the Syncrude project, reported that the plant is currently operating at reduced rates and that production is expected to return to normal operating rates by early August. We do not expect this supply disruption to have a long-term impact on the volumes of crude oil flowing from Western Canada into the U.S.

Western Canadian crude oil production is projected to increase throughout the next decade, driven primarily by developments in Alberta’s oil sands region. In June 2017, the Canadian Association of Petroleum Producers, or CAPP, projected that the supply of crude oil from Western Canada will grow by approximately 760,000 Bpd by 2020 and 1.1 million Bpd by 2025 relative to 2016.

Additionally, we expect the recent consolidation of Western Canadian oil sands production assets among active Canadian producers will drive further increases in crude oil production as cost savings and technological advancements made during the recent commodity price downturn are incorporated into future development plans. For example, in May 2017, Cenovus Energy Inc. acquired the remaining 50% ownership interest in its Foster Creek Christina Lake partnership and the majority of the Deep Basin conventional assets previously owned by the ConocoPhillips Company. In June 2017, Cenovus announced a 10,000 Bpd or approximately 30% increase in its expected Foster Creek Phase H production capacity due to redesign and optimization efforts, as well as a 20,000 Bpd or approximately 40% increase for its Narrows Lake Phase A resulting from the first commercial implementation of solvents following successful pilot results.

As a result, we continue to expect that growing crude oil supplies from Western Canada will exceed available pipeline takeaway capacity, causing a widening of WCS spreads and increasing demand for rail transportation solutions, consistent with previous cycles. Our expectations are supported by multiple industry forecasts which project an increase in the demand for rail takeaway 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 locations to meet expected future takeaway needs. Additionally, we believe our Stroud terminal near the Cushing hub represents the most advantaged rail destination for Western Canadian crude oil given established connectivity from Cushing to multiple refining centers across the U.S., including underutilized pipelines to major refining centers along the Gulf Coast. We expect these advantages, including our recently established origin-to-destination capabilities, should result in re-contracting and expansion opportunities across our terminal network.

Our sponsor retained the right to develop certain expansions of our Hardisty and Stroud terminals, which they are actively pursuing. These expansions may include solutions to transport heavier grades of crude oil produced in Western Canada, which our sponsor believes will maximize benefits to producers, refiners and railroads. Additionally, our sponsor, through its Texas Deepwater Partners joint venture, is engaged with potential customers to support the development of a large scale energy logistics terminal on the Houston Ship Channel. The 988-acre facility could support up to twelve million barrels of liquid storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities. We anticipate that any such projects developed

by our sponsor would be subject to the right of first offer in our favor contained in the omnibus agreement between us and USD.

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

Our terminalling services segment includes our crude oil and ethanol terminals. 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 Casper terminal, acquired in November 2015, is a crude oil storage, blending and railcar loading terminal. The terminal currently offers six customer-dedicated 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 capabilities. Our Casper terminal is supplied with multiple grades of Canadian crude oil through a direct connection with Spectra Energy Partners’ Express Pipeline, as well as local production through two truck unloading units. 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 by rail from producers 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. Substantially all of our cash flows are generated from multi-year, take-or-pay terminal services agreements with customers at our Hardisty and Casper terminals that include minimum monthly commitment fees. Our West Colton terminal operates under a minimum monthly commitment fee arrangement that is terminable on 150 days’ notice. Our recently acquired Stroud terminal, as previously described, is also included in our terminalling services segment from the June 2, 2017, acquisition date and is expected to begin producing revenue upon the commencement of its terminalling services agreement in October 2017.

Fleet Services

We provide our customers with leased railcars and fleet services related to the transportation of liquid hydrocarbons and biofuels by rail on a multi-year, take-or-pay basis under master fleet services agreements for initial terms ranging from five to nine years. The weighted average remaining contract life on our railcar fleet is approximately 3.6 years. We do not own any railcars. As of June 30, 2017, our railcar fleet consisted of 2,953 railcars, which we leased from various railcar manufacturers and financial entities, including 2,108 coiled and insulated, or C&I, railcars. We have assigned certain payment and performance obligations under the leases and master fleet service agreements for 2,613 of the railcars to other parties, but we have retained certain rights and obligations with respect to the servicing of these railcars.

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 and maintenance expenses; 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, changes in restricted cash, interest, income taxes, foreign currency transaction gains and losses, adjustments related to deferred revenue associated with minimum monthly commitment fees 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 cash from operations, 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 Adjusted EBITDA and DCF to the most directly comparable financial measure calculated and presented in accordance with GAAP:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA and Distributable cash flow:
Net cash provided by operating activities	$	9,256		$	13,354		$	22,071		$	22,578
Add (deduct):
Amortization of deferred financing costs	(215		)	(215		)	(430		)	(430		)
Deferred income taxes	(249		)	50			(307		)	96
Changes in accounts receivable and other assets	3,180			467			1,353			(1,507		)
Changes in accounts payable and accrued expenses	1,486			1,105			1,086			1,937
Changes in deferred revenue and other liabilities	1,400			(1,557		)	2,520			(2,100		)
Change in restricted cash	209			(1,793		)	230			633
Interest expense, net	2,513			2,533			5,116			4,716
Provision for (benefit from) income taxes	(2,434		)	1,917			(1,249		)	3,714
Foreign currency transaction gain ⁽¹⁾	(100		)	(15		)	(70		)	(145		)
Deferred revenue associated with minimum monthly commitment fees ⁽²⁾	62			424			142			1,187
Adjusted EBITDA	15,108			16,270			30,462			30,679
Add (deduct):
Cash paid for income taxes ⁽³⁾	(798		)	(1,486		)	(1,414		)	(3,196		)
Cash paid for interest	(2,575		)	(2,180		)	(4,937		)	(3,987		)
Maintenance capital expenditures	(72		)	(18		)	(198		)	(18		)
Distributable cash flow	$	11,663		$	12,586		$	23,913		$	23,478


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

⁽²⁾

Represents deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to our customers. Amounts presented are net of: (a) the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue; (b) revenue recognized in the current period that was previously deferred; and (c) expense recognized for previously prepaid Gibson pipeline fees, which correspond with the revenue recognized that was previously deferred. Refer to the discussion in Note 6. Deferred Revenue of our consolidated financial statements included in Part I, Item 1 of this report.


⁽³⁾	Includes a partial refund of approximately $0.7 million (representing C$0.9 million) received in the three months ended March 31, 2017, for our 2015 foreign income taxes.

Operating and Maintenance Expenses

Our management seeks to maximize the profitability of our operations by effectively managing 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 terminals 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.

Our operating expenses are comprised primarily of pipeline fees, repairs and maintenance expenses, materials and supplies, subcontracted rail expenses, utility costs, insurance premiums and rent for facilities and equipment. With additional volumes of crude oil handled at our terminals, we expect to incur additional operating costs, including subcontracted rail services and pipeline fees. 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.

Volumes

The amount of Terminalling services revenue we generate depends on minimum customer commitment fees and the volume of crude oil that we handle at our terminals in excess of those minimum commitments, as well as the volume of biofuels transloaded at our ethanol terminals. 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 crude 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 impacted 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.

Factors Affecting the Comparability of Our Financial Results

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, 2016. 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.

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

Foreign Currency Exchange Rates

We derive a significant amount of operating income from our Canadian operations, particularly our Hardisty terminal. Given our exposure to fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar, our operating income and assets which are denominated in Canadian dollars will be positively affected when the Canadian dollar increases in relation to the U.S. dollar and will be negatively affected when the Canadian dollar decreases relative to the U.S. dollar, assuming all other factors are held constant. Conversely, our liabilities which are denominated in Canadian dollars will be positively affected when the Canadian dollar decreases in relation to the U.S. dollar and will be negatively affected when the Canadian dollar increases relative to the U.S. dollar.

We have entered into derivative contracts to mitigate a significant portion of the potential impact that fluctuations in the value of the Canadian dollar relative to the U.S. dollar may have on cash flows generated by our Hardisty terminal operations through 2017. As a result, we do not expect foreign currency exchange rates to have a significant impact on our operating cash flows in the near term. Our derivative contracts, which cover the majority of our Canadian cash flows, secured a minimum exchange rate of 0.84 U.S. dollars per Canadian dollar for our 2016 fiscal year and effectively fix an exchange rate of 0.78 U.S. dollars per Canadian dollar for our 2017 fiscal year. The average exchange rates for the Canadian dollar in relation to the U.S. dollar were 0.7495 and 0.7524 for the six months ended June 30, 2017 and 2016, respectively.

Income Tax Expense

In 2016, we adopted a methodology for determining the return attributable to our Canadian subsidiaries based upon completion of a study we initially commissioned in 2015, which modifies the amount of Canadian federal and provincial income taxes to which our Canadian operations are subject. We calculated our 2017 and 2016 income tax provisions for our Canadian operations utilizing this methodology. Our 2017 provision for income taxes includes a reduction to our estimated income tax liability for 2016, based upon the Canadian federal and provincial income tax returns for 2016 we filed in June 2017, which resulted in expected refunds of approximately $2.6million (C$3.4 million). We have also reduced the estimated income tax expense we expect to incur for 2017, based upon the income tax returns filed for 2016.

RESULTS OF OPERATIONS

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

The following table summarizes our operating results by business segment and corporate charges for the periods indicated:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Operating income (loss)
Terminalling services	$	10,683		$	11,211		$	21,800		$	21,188
Fleet services	464			455			819			959
Corporate and other	(2,385		)	(2,249		)	(4,621		)	(5,207		)
Total operating income	8,762			9,417			17,998			16,940
Interest expense	2,513			2,533			5,120			4,716
Loss (gain) associated with derivative instruments	401			(253		)	612			1,270
Foreign currency transaction gain	(100		)	(15		)	(70		)	(145		)
Other expense, net	3			—			8			—
Provision for (benefit from) income taxes	(2,434		)	1,917			(1,249		)	3,714
Net income	$	8,379		$	5,235		$	13,577		$	7,385

Summary Analysis of Operating Results

Changes in our operating results for the three and six months ended June 30, 2017, as compared with our operating results for the three and six months ended June 30, 2016, were primarily driven by:

•

additional terminalling services revenue recognized from amounts previously deferred, which resulted from the expiration of greater amounts of make-up rights granted to customers of our Hardisty terminal in the current year relative to the prior year, partially offset by two months without revenue from the San Antonio rail terminal resulting from the termination of our customer agreement as of May 2017;


•	additional pipeline fees recognized as expense from previously prepaid amounts, which correspond with the recognition of previously deferred revenue from our Hardisty terminal;


•	a higher weighted average interest rate in 2017 relative to 2016 and a higher weighted average balance of debt outstanding related to our acquisition of the Stroud terminal which has since been repaid; and

•

benefits from income taxes resulting from revisions to our estimates of 2016 Canadian federal and provincial income tax provisions, based on the actual taxable income of our Canadian operations. As a result, we expect to receive refunds totaling C$3.4 million (approximately $2.6 million) during the second half of 2017, which we recorded as a reduction to our provision for income taxes during the three months ended June 30, 2017. We also updated our estimates of 2017 Canadian federal and provincial income tax provisions, which further reduced our provision for income taxes producing a benefit from income taxes for the six months ended June 30, 2017.

Although we acquired the Stroud terminal in June 2017 and began incurring related expenses in the second quarter of 2017, our customer contracts do not commence until October 1, 2017, at which time we expect our operation of the terminal and related facilities to positively affect the operating results of our terminalling services business.

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

RESULTS OF OPERATIONS - BY SEGMENT

TERMINALLING SERVICES

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Revenues
Terminalling services	$	24,495		$	25,215		$	49,794		$	48,888
Railroad incentives	6			22			21			37
Freight and other reimbursables	89			19			110			19
Total revenues	24,590			25,256			49,925			48,944
Operating costs
Subcontracted rail services	1,795			2,026			3,808			4,069
Pipeline fees	5,369			5,338			10,786			10,052
Freight and other reimbursables	89			19			110			19
Operating and maintenance	500			692			1,111			1,507
Selling, general and administrative	1,185			1,056			2,400			2,290
Depreciation and amortization	4,969			4,914			9,910			9,819
Total operating costs	13,907			14,045			28,125			27,756
Operating income	10,683			11,211			21,800			21,188
Interest expense	—			352			170			682
Loss (gain) associated with derivative instruments	401			(253		)	612			1,270
Foreign currency transaction loss (gain)	(13		)	5			(13		)	(75		)
Other expense, net	3			—			8			—
Provision for (benefit from) income taxes	(2,423		)	1,948			(1,418		)	3,731
Net income	$	12,715		$	9,159		$	22,441		$	15,580
Average daily terminal throughput (bpd)	22,783			30,640			27,433			31,063

Three months ended June 30, 2017 compared with three months ended June 30, 2016

Terminalling Services Revenue

Revenue generated by our Terminalling services segment decreased $0.7 million to $24.6 million for the three months ended June 30, 2017, from $25.3 million for the three months ended June 30, 2016. This decrease was primarily due to the termination of our customer agreement at the San Antonio terminal as of May 2017. Our agreement with Canadian Pacific Railway Limited for a per car incentive expired on June 30, 2017. As a result, we will no longer receive railroad incentives for shipments from our Hardisty terminal.

Terminalling services revenue excludes amounts we received as payment for minimum monthly commitment fees from our customers that we have deferred and recorded as short-term liabilities in our consolidated balance sheet. We have deferred recognizing this revenue in connection with the minimum monthly commitment fees paid by customers of our Hardisty terminal that are in excess of their actual throughput volumes due to the make-up rights we have granted them under their terminalling services agreements with us. Customers of our Hardisty terminal can use these make-up rights for periods of up to six months to offset throughput volumes in excess of their minimum monthly commitments in future periods, to the extent capacity is available for the excess volume. We expect to recognize the deferred amounts in revenue as our customers use these rights, upon expiration of the make-up period, or when our customers’ ability to utilize those rights is determined to be remote. We recognized approximately $12.8 million of previously deferred

revenues during the three months ended June 30, 2017, as compared with $12.4 million during the three months ended June 30, 2016. The recognition of greater amounts of previously deferred revenue in the current period is due to greater amounts of make-up rights expiring in the current period relative to the same period for the prior year.

Our terminalling service revenue would have been approximately $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 June 30, 2017, was the same as the average exchange rate for the three months ended June 30, 2016.

Operating Costs

The operating costs of our Terminalling services segment decreased $0.1 million to $13.9 million for the three months ended June 30, 2017, compared with $14.0 million for the three months ended June 30, 2016. This decrease was primarily due to a decrease in subcontracted rail services due to the termination of our customer agreement at the San Antonio terminal along with lower operating and maintenance costs, offset by a slight increase in selling, general and administrative costs. Except as otherwise discussed below our operating costs for the three months ended June 30, 2017, were essentially unchanged from the three months ended June 30, 2016.

We actively manage our operating costs in an effort to align with the current economic environment. As economic conditions improve, our costs may increase to more normalized levels.

Subcontracted rail services. Our subcontracted rail services costs decreased $0.2 million to $1.8 million for the three months ended June 30, 2017, from $2.0 million for the three months ended June 30, 2016, primarily due to the termination of our customer agreement at the San Antonio terminal as of May 2017.

Operating and maintenance. Operating and maintenance expenses decreased approximately $0.2 million to approximately $0.5 million for the three months ended June 30, 2017, from approximately $0.7 million for the three months ended June 30, 2016, primarily due to decreased repairs and maintenance in 2017 directly related to capital improvements completed in 2016 at the Casper terminal to upgrade equipment, providing better reliability and lower maintenance costs in the current and future years.

Other Expenses

Interest expense. We had no interest expense for our Terminalling services segment for the three months ended June 30, 2017, as compared with $0.4 million for the three months ended June 30, 2016, due to our repayment of all amounts outstanding on the Term Loan Facility during the three months ended March 31, 2017, which eliminated any future interest expense of our Terminalling Services business directly attributable to this Facility.

Loss (gain) associated with derivative instruments. In June 2015 and April 2016, we entered into derivative contracts to mitigate our exposure to fluctuations in foreign currency exchange rates, specifically between the U.S. dollar and the Canadian dollar, associated with the operations at our Hardisty terminal. We record all of our derivative financial instruments at fair market value in our consolidated financial statements, which we adjust each period for changes in the fair market value.

From March 31, 2017 to June 30, 2017, the exchange rate between the U.S. dollar and the Canadian dollar increased from a spot rate of 0.7502 to a spot rate of 0.7703 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our derivative contracts maturing on or after June 30, 2017, relative to the value of these contracts at March 31, 2017, producing a non-cash loss of approximately $0.4 million for the three months ended June 30, 2017.

From March 31, 2016 to June 30, 2016, the exchange rate between the U.S. dollar and the Canadian dollar increased from a spot rate of 0.7711 to a spot rate of 0.7718 U.S. dollars for each Canadian dollar, which had no significant impact on the value of the derivative contracts we held at March 31, 2016. However, the derivative contracts we entered into in April increased in value, producing a gain of approximately $0.3 million for the three months ended June 30, 2016.

Provision for 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 provision for income taxes for the Terminalling services segment decreased $4.4 million to a benefit of $2.4 million for the three months ended June 30, 2017. During the three months ended June 30, 2017, upon filing our Canadian federal and provincial income tax returns for 2016, we revised our estimates of 2016 Canadian federal and provincial income tax provisions based on the actual taxable income of our Canadian operations for 2016. As a result, we expect to receive refunds totaling C$3.4 million (approximately $2.6 million) during the second half of 2017, which we reflected as a reduction to our “Provision for income taxes” during the three months ended June 30, 2017, producing a benefit. We also decreased our estimates of 2017 Canadian federal and provincial income tax provisions based upon the information derived from our 2016 Canadian federal and provincial income tax returns filed and our projections of 2017 taxable income. We expect to pay reduced amounts of Canadian federal and provincial income taxes for the remainder of 2017 based on our revised estimates.

Six months ended June 30, 2017 compared with six months ended June 30, 2016

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $1.0 million to $49.9 million for the six months ended June 30, 2017, from $48.9 million for the six months ended June 30, 2016. This increase was primarily due to the recognition of greater amounts of previously deferred revenues in the current year as compared to the prior year, partially offset by decreased revenue in our San Antonio terminal due to the termination of our customer agreement. In addition, our terminalling service revenue for the six months ended June 30, 2017, was minimally affected by a lower average exchange rate for the Canadian dollar relative to the U.S. dollar.

Operating Costs

The operating costs of our Terminalling services segment increased $0.4 million to $28.1 million for the six months ended June 30, 2017. This increase was primarily due to higher pipeline fees associated with increased revenues and was mostly offset by lower subcontracted rail and operating and maintenance costs. Except as otherwise discussed below, our operating costs for the six months ended June 30, 2017, were essentially unchanged from the six months ended June 30, 2016. Our terminalling services operating costs for the six months ended June 30, 2017, were minimally affected by a lower average exchange rate for the Canadian dollar relative to the U.S. dollar in relation to the average exchange rate for the six months ended June 30, 2016.

We actively manage our operating costs in an effort to align with the current economic environment. As economic conditions improve, our costs may increase to more normalized levels.

Subcontracted rail services. Our subcontracted rail services costs decreased $0.3 million to $3.8 million for the six months ended June 30, 2017, from $4.1 million for the six months ended June 30, 2016, primarily due to the termination of our customer agreement at the San Antonio terminal.

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. We may defer recognizing portions of these costs as expense until such time as we recognize the related deferred revenue following the expiration of any make-up rights provisions. Pipeline fees increased $0.7 million to $10.8 million for the six months ended June 30, 2017, from $10.1 million for the six months ended June 30, 2016, primarily due to the increase in revenues recognized at the Hardisty terminal.

Operating and maintenance. Operating and maintenance expenses decreased approximately $0.4 million to approximately $1.1 million for the six months ended June 30, 2017, from approximately $1.5 million for the six months ended June 30, 2016, primarily due to decreased repairs and maintenance in 2017 directly related to capital improvements completed in 2016 at the Casper terminal to upgrade equipment, providing better reliability and lower maintenance costs in the current and future years.

Other Expenses

Interest expense. Interest expense for our Terminalling services segment decreased by $0.5 million to $0.2 million for the six months ended June 30, 2017, from $0.7 million for the six months ended June 30, 2016, due to our repayment of the outstanding balance of the Term Loan Facility in the first quarter of 2017, which eliminated any future interest expense of our Terminalling Services business directly attributable to this Facility.

Loss (gain) associated with derivative instruments. We record all of our derivative financial instruments at fair market value in our consolidated financial statements, which we adjust each period for changes in the fair market value.

From December 31, 2016 to June 30, 2017, the exchange rate between the U.S. dollar and the Canadian dollar increased from a spot rate of 0.7440 to a spot rate of 0.7703 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our derivative contracts maturing on or after June 30, 2017, relative to the value of these contracts at December 31, 2016, producing a non-cash loss of approximately $0.6 million for the six months ended June 30, 2017.

From December 31, 2015 to June 30, 2016, the exchange rate between the U.S. dollar and the Canadian dollar increased from a spot rate of 0.7210 to a spot rate of 0.7718 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our derivative contracts maturing on or after June 30, 2016, relative to the value of these contracts at December 31, 2015, producing a non-cash loss of approximately $1.3 million for the six months ended June 30, 2016.

Provision for income taxes. Our provision for income taxes for the Terminalling services segment decreased $5.1 million to a benefit of $1.4 million for the six months ended June 30, 2017, as compared with an expense of $3.7 million for the six months ended June 30, 2016. During the six months ended June 30, 2017, upon filing our Canadian federal and provincial income tax returns for 2016, we revised our estimates of 2016 Canadian federal and provincial income tax provisions based on the actual taxable income of our Canadian operations for 2016. As a result, we expect to receive refunds totaling C$3.4 million (approximately $2.6 million) during the second half of 2017, which we reflected as a reduction to our “Provision for income taxes” during the six months ended June 30, 2017, producing a benefit. We also decreased our estimates of 2017 Canadian federal and provincial income tax provisions based upon the information derived from our 2016 Canadian federal and provincial income tax returns filed and our projections of 2017 taxable income. We expect to pay reduced amounts of Canadian federal and provincial income taxes for the remainder of 2017 based on our revised estimates.

FLEET SERVICES

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
	(in thousands)
Revenues
Fleet leases	$	1,534	$	1,538		$	3,067	$	3,071
Fleet services	746		753			1,493		1,506
Freight and other reimbursables	119		331			256		714
Total revenues	2,399		2,622			4,816		5,291
Operating costs
Fleet leases	1,534		1,538			3,067		3,071
Freight and other reimbursables	119		331			256		714
Operating and maintenance	94		91			190		146
Selling, general and administrative	188		207			484		401
Total operating costs	1,935		2,167			3,997		4,332
Operating income	464		455			819		959
Foreign currency transaction loss (gain)	2		(20		)	2		(70		)
Provision for (benefit from) income taxes	181		(32		)	315		(18		)
Net income	$	281	$	507		$	502	$	1,047

Three months ended June 30, 2017 compared with three months ended June 30, 2016

Fleet Services Revenue

Revenues from our Fleet services segment decreased $0.2 million to $2.4 million for the three months ended June 30, 2017, from $2.6 million for the three months ended June 30, 2016. The decrease was primarily attributable to a lower amount of reimbursable repair and maintenance work that we completed on behalf of our customers. “Freight and other reimbursables” revenues were exactly offset by “Freight and other reimbursables” costs.

Operating Costs

Operating costs primarily consist of railcar leases and related expenses incurred for services provided to customers of our terminals. Operating costs of our Fleet services segment decreased to $1.9 million for the three months ended June 30, 2017, from $2.2 million for the three months ended June 30, 2016, primarily due to a decrease in “Freight and other reimbursables” costs. “Freight and other reimbursables” costs were exactly offset by “Freight and other reimbursables” revenues.

Other Expenses

Provision for income taxes. The provision for income taxes of our Fleet services segment increased $213 thousand to $181 thousand for the three months ended June 30, 2017, due to reversals of temporary differences at USD Rail LP, producing an increase in taxable income. USD Rail LP is treated as a corporation for United States federal income tax purposes and subject to income tax at a marginal rate of approximately 34%.

Six months ended June 30, 2017 compared with six months ended June 30, 2016

Fleet Services Revenue

Revenues from our Fleet services segment decreased $0.5 million to $4.8 million for the six months ended June 30, 2017, from $5.3 million for the six months ended June 30, 2016. Changes in the components of our Fleet

services revenue during the six months ended June 30, 2017, as compared with the same period in 2016, occurred primarily for the reasons noted above in our three-month analysis.

Operating Costs

Operating costs primarily consist of railcar leases and related expenses incurred for services provided to customers of our terminals. Operating costs of our Fleet services segment decreased $0.3 million to $4.0 million for the six months ended June 30, 2017, from $4.3 million for the six months ended June 30, 2016. Changes in the components of our Fleet services operating costs during the six months ended June 30, 2017, as compared with the same period in 2016, occurred primarily for the reasons noted above in our three-month analysis.

Other Expenses

Provision for income taxes. The provision for income taxes of our Fleet services segment increased $333 thousand for the six months ended June 30, 2017, primarily for the reasons noted above in our three-month analysis.

CORPORATE ACTIVITIES

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Operating costs
Selling, general and administrative	$	2,385		$	2,249		$	4,621		$	5,207
Operating loss	(2,385		)	(2,249		)	(4,621		)	(5,207		)
Interest expense	2,513			2,181			4,950			4,034
Foreign currency transaction gain	(89		)	—			(59		)	—
Provision for (benefit from) income taxes	(192		)	1			(146		)	1
Net loss	$	(4,617	)	$	(4,431	)	$	(9,366	)	$	(9,242	)

Three months ended June 30, 2017 compared with three months ended June 30, 2016

Costs associated with our corporate activities increased by $0.2 million to $4.6 million for the three months ended June 30, 2017, from $4.4 million for the three months ended June 30, 2016. “Selling, general and administrative” expenses increased by $0.1 million, primarily due to additional unit based compensation expense related to Phantom Units granted in February 2017 to directors and employees of our general partner and its affiliates under our Long-term Incentive Plan. This increase was partially offset by lower consulting costs associated with a project to enhance our compliance and internal control systems, which we completed in the second quarter of 2016. Interest expense increased by $0.3 million during the three months ended June 30, 2017, primarily due to a greater weighted average balance outstanding on our Revolving Credit Facility along with a higher weighted average interest rate as compared with the same period of 2016. We had a benefit of $0.2 million for income taxes for the three months ended June 30, 2017, due to a change in our estimate for Texas Franchise tax expense following our review of amounts included in the computations associated with our corporate activities.

Six months ended June 30, 2017 compared with six months ended June 30, 2016

Costs associated with our corporate activities increased by $0.1 million to $9.4 million for the six months ended June 30, 2017, from the six months ended June 30, 2016. “Selling, general and administrative” expenses decreased by $0.6 million, primarily due to lower consulting and legal fees. Our consulting costs were lower for the reasons cited above in our three months analysis and legal fees were lower because we did not incur legal costs for financing and integrating the Casper terminal during the six months ended June 30, 2017, as we did during the six months ended June 30, 2016. Interest expense increased by $0.9 million during the six months ended June 30, 2017, primarily due to a larger weighted average balance outstanding on our Revolving Credit Facility, as well as higher weighted average

rates of interest relative to the same period in 2016. We had a benefit of $0.1 million for income taxes for the six months ended June 30, 2017, for the same reasons noted above in our three months analysis.

LIQUIDITY AND CAPITAL RESOURCES

Our principal liquidity requirements include:


•	making distributions to our unitholders,


•	financing current operations,


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


•	servicing our debt.

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 $400 million senior secured credit agreement, issuances of debt and additional equity securities, 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 working capital and capital expenditure requirements and to make quarterly cash distributions.

Equity Offering

In June 2017, we issued and sold 3,000,000 common units in an underwritten public offering at a public offering price of $11.60 per unit. We received proceeds, net of underwriting discounts, commissions and offering costs of approximately $33.7 million. We used the net proceeds we received from this offering to repay amounts outstanding under our Revolving Credit Facility, a portion of which we borrowed to fund our acquisition of the Stroud terminal.

Credit Agreement

We have a $400 million senior secured credit agreement, the Credit Agreement, previously comprised of a $300 million revolving credit facility, the Revolving Credit Facility, and a $100 million term loan (borrowed in Canadian dollars), the Term Loan Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Agreement is a five year committed facility that matures October 15, 2019. In March 2017, we repaid in total the amounts previously outstanding on the Term Loan Facility. As a result, our Revolving Credit Facility comprises the full $400 million capacity of our Credit Agreement, subject to the limits set forth therein. As of June 30, 2017, our outstanding indebtedness consists solely of amounts borrowed on our Revolving Credit Facility.

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. 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 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 following table presents our available liquidity as of the dates indicated:



	June 30, 2017		December 31, 2016
	(in millions)
Cash and cash equivalents	$	7.2	$	11.7
Aggregate borrowing capacity under Credit Agreement	400.0		400.0
Less: Term Loan Facility amounts outstanding	—		10.1
Revolving Credit Facility amounts outstanding	206.0		213.0
Letters of credit outstanding	—		—
Total available liquidity ⁽¹⁾	$	201.2	$	188.6

⁽¹⁾

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:



	Six Months Ended June 30,
	2017			2016
	(in thousands)
Net cash provided by (used in):
Operating activities	$	22,071		$	22,578
Investing activities	(25,773		)	(246		)
Financing activities	(856		)	(23,375		)
Effect of exchange rates on cash	49			439
Net change in cash and cash equivalents	$	(4,509	)	$	(604	)

Operating Activities

Net cash provided by operating activities decreased by $0.5 million to $22.1 million for the six months ended June 30, 2017, from $22.6 million for the six months ended June 30, 2016. The decrease was primarily attributable to the net changes in our working capital accounts associated with the timing of receipts and payment of our accounts receivable, accounts payable and deferred revenue balances.

Investing Activities

Net cash used in investing activities increased by $25.5 million to $25.8 million for the six months ended June 30, 2017, from $0.2 million for the six months ended June 30, 2016. The increase was primarily attributable to our purchase of the Stroud terminal in June 2017.

Financing Activities

Net cash used in financing activities decreased to $0.9 million for the six months ended June 30, 2017, from $23.4 million for the six months ended June 30, 2016. We obtained $33.7 million of net proceeds from our public offering in June 2017. We had net repayments on our long-term debt of $17.3 million for the six months ended June 30, 2017, compared with a net repayment of $8.9 million for the six months ended June 30, 2016. Additionally,

we paid cash distributions of $16.1 million and participant withholding taxes associated with vested Phantom Units of $1.1 million during the six months ended June 30, 2017, both of which exceeded amounts paid during the six months ended June 30, 2016, 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, changes in restricted cash, interest, income taxes, foreign currency transaction gains and losses, adjustments related to deferred revenue associated with minimum monthly commitment fees 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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	15,811		$	17,095		$	32,248		$	33,230
Fleet services	464			455			819			959
Corporate activities ⁽¹⁾	(1,167		)	(1,280		)	(2,605		)	(3,510		)
Total Adjusted EBITDA	15,108			16,270			30,462			30,679
Add (deduct):
Amortization of deferred financing costs	215			215			430			430
Deferred income taxes	249			(50		)	307			(96		)
Changes in accounts receivable and other assets	(3,180		)	(467		)	(1,353		)	1,507
Changes in accounts payable and accrued expenses	(1,486		)	(1,105		)	(1,086		)	(1,937		)
Changes in deferred revenue and other liabilities	(1,400		)	1,557			(2,520		)	2,100
Change in restricted cash	(209		)	1,793			(230		)	(633		)
Interest expense, net	(2,513		)	(2,533		)	(5,116		)	(4,716		)
Benefit from (provision for) income taxes	2,434			(1,917		)	1,249			(3,714		)
Foreign currency transaction gain ⁽²⁾	100			15			70			145
Deferred revenue associated with minimum monthly commitment fees ⁽³⁾	(62		)	(424		)	(142		)	(1,187		)
Net cash provided by operating activities	$	9,256		$	13,354		$	22,071		$	22,578


⁽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 deferred revenue associated with minimum monthly commitment fees in excess of throughput utilized, which fees are not refundable to our customers. Amounts presented are net of: (a) the corresponding prepaid Gibson pipeline fee that will be recognized as expense concurrently with the recognition of revenue; (b) revenue recognized in the current period that was previously deferred; and (c) expense recognized for previously prepaid Gibson pipeline fees, which correspond with the revenue recognized that was previously deferred. Refer to discussion in Note 6 - Deferred Revenues of our consolidated financial statements in Part 1. Item 1.

Terminalling Services Segment

Adjusted EBITDA from our Terminalling services segment decreased $1.3 million to $15.8 million for the three months ended June 30, 2017, from $17.1 million for the three months ended June 30, 2016, and decreased $1.0 million

to $32.2 million for the six months ended June 30, 2017, from $33.2 million for the six months ended June 30, 2016. The decrease in both periods is primarily the result of discontinuing the operations of our San Antonio terminal in May 2017, following the conclusion of our customer's agreement with us, coupled with a smaller benefit from the settlement of our derivative contracts and a lower cash adjustment associated with our minimum monthly commitment fees. For additional discussion of the operating results of our terminalling segment refer to Results of Operations - By Segment — Terminalling Services.

Fleet Services Segment

Adjusted EBITDA from our Fleet services segment was essentially unchanged for the three months ended June 30, 2017, as compared with the three months ended June 30, 2016, and decreased $0.1 million to $0.8 million for the six months ended June 30, 2017, as compared with the six months ended June 30, 2016. This decrease was primarily the result of a slight increase in “Selling, general and administrative expenses.”

Cash Requirements

Our primary requirements for capital are for funding capital expenditures, including maintenance capital expenditures, acquisitions and the costs we may incur to construct new assets, as well as servicing our debt and 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 $198 thousand of maintenance capital expenditures during the six months ended June 30, 2017, primarily for the replacement of pumping and generating equipment at our terminals and repaving of roads to access our terminal storage tanks. 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.

Our total expansion capital expenditures for the six months ended June 30, 2017, was $25.6 million, primarily related to our purchase of the Stroud terminal, which we funded with amounts borrowed on our Revolving Credit Facility. We expect to fund future capital expenditures from cash on our balance sheet, cash flow generated by our operations, borrowings under our Revolving Credit Facility 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 six months ended June 30, 2017, we repaid $10.3 million on our Term Loan Facility (the equivalent of C$13.6 million) and $47.0 million on our Revolving Credit Facility. These payments were partially offset by proceeds from borrowing $40.0 million on our Revolving Credit Facility, which we used to fund our acquisition of the Stroud terminal, for general partnership purposes and other capital expenditures.

Distributions

We intend to pay a minimum quarterly distribution of at least $0.2875 per unit per quarter. Our current quarterly distribution of $0.34 per unit equates to approximately $9.0 million per quarter, or $36.0 million per year, based on the number of common, Class A, subordinated, and general partner units outstanding as of August 4, 2017. 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, loss reserves, 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.

SUBSEQUENT EVENTS

Refer to Note 18. 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 17. Recent Accounting Pronouncements Not Yet Adopted 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 8 - 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.


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, 2016, except as discussed below.

The following table provides summarized information about our outstanding foreign currency contracts at the specified dates:



	At June 30, 2017						At December 31, 2016
	Notional (C$)		Forward Rate ⁽¹⁾	Market Price⁽¹⁾	Fair Value		Fair Value
					(in thousands)
Forward contracts maturing in 2017
March 31, 2017	C$	8,300,000	0.7804	—	$	—	$	299
June 30, 2017	C$	8,400,000	0.7805	—	—		296
September 29, 2017	C$	8,400,000	0.7807	0.7725	69		290
December 29, 2017	C$	8,400,000	0.7809	0.7732	65		282
Total					$	134	$	1,167


⁽¹⁾	Forward rates and market prices are denoted in amounts where a Canadian dollar is exchanged for the indicated amount of U.S. dollars. The forward rate represents the rate we will receive upon settlement and the market price represents the rate we would expect to pay had the contract been settled on June 30, 2017.

As a part of our purchase of the Stroud terminal and related facilities, we acquired crude oil used as line fill in the crude oil pipeline and tank bottoms for the storage tanks. We intend to sell this crude oil prior to the end of 2017. Due to our long position with respect to crude oil, fluctuations in crude oil prices could affect our results of operations, cash flows and financial positions. In order to mitigate this risk we have entered into commodity swaps to fix the price we will receive upon our sale of the crude oil.

In June 2017, we entered into two separate fixed-for-floating swap contracts with an aggregate notional amount of 31,778 barrels, or bbl, to manage our exposure to fluctuating crude oil prices. Each swap contract effectively fixes the price we will receive upon our delivery of the crude oil. The first contract for 18,395 bbl will settle in July 2017 at $47.20 per barrel and the second contract for 13,383 bbl will settle in October 2017 at $47.70 per barrel.

The following table provides summarized information about our commodity derivatives at the specified dates:



	At June 30, 2017
	Notional	Market Price ⁽¹⁾		Fixed Price ⁽²⁾		Fair Value
	(in Bbls)					(in thousands)
Commodity swaps maturing in 2017
July 2017	18,395	$	46.13	$	47.20	$	20
October 2017	13,383	$	46.86	$	47.70	$	11
	31,778					$	31


⁽¹⁾	The market price represents the price we would pay to purchase one barrel of crude oil of the grade specified for the settlement date as set forth in the derivative contract as of June 30, 2017.


⁽²⁾	The fixed price represents the fixed price we will receive upon our sale of one barrel of crude oil of the grade specified for the settlement date as set forth in the derivative contract.


Item 4.	Controls and Procedures.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow for timely decisions regarding required disclosure and to ensure information is recorded, processed, summarized and reported within the

time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2017, at the reasonable assurance level.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

We did not make any changes in our internal control over financial reporting during the three months ended June 30, 2017, 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 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 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, 2016. No material changes to such risk factors have occurred during the three and six months ended June 30, 2017.

Item 6. Exhibits

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

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:	August 8, 2017	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	August 8, 2017	By:	/s/ Adam Altsuler
			Adam Altsuler Chief Financial Officer (Principal Financial Officer)



		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).

10.1*†		Marketing service agreement dated as of May 31, 2017 by and between USD Marketing LLC and Stroud Crude Terminal LLC.

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.