USD Partners - 10-Q quarterly report FY

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended September 30, 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 November 6, 2017, there were 19,537,971 common units, 6,278,127 subordinated units, 82,500 Class A units and 461,136 general partner units outstanding.

TABLE OF CONTENTS

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(unaudited; in thousands, except per unit amounts)
Revenues
Terminalling services	$	21,799		$	24,078		$	67,335		$	69,560
Terminalling services — related party	4,716			1,736			8,974			5,142
Railroad incentives	4			24			25			61
Fleet leases	643			643			1,929			1,933
Fleet leases — related party	1,013			890			2,794			2,671
Fleet services	470			475			1,405			613
Fleet services — related party	218			279			776			1,647
Freight and other reimbursables	118			218			483			944
Freight and other reimbursables — related party	—			—			1			—
Total revenues	28,981			28,343			83,722			82,571
Operating costs
Subcontracted rail services	2,340			2,004			6,148			6,073
Pipeline fees	6,367			5,492			17,153			15,544
Fleet leases	1,656			1,534			4,723			4,605
Freight and other reimbursables	118			218			484			944
Operating and maintenance	749			746			2,050			2,399
Selling, general and administrative	2,221			2,505			6,898			7,472
Selling, general and administrative — related party	1,477			1,438			4,305			4,369
Depreciation and amortization	5,254			4,906			15,164			14,725
Total operating costs	20,182			18,843			56,925			56,131
Operating income	8,799			9,500			26,797			26,440
Interest expense	2,388			2,572			7,508			7,288
Loss (gain) associated with derivative instruments	667			(349		)	1,279			921
Foreign currency transaction loss (gain)	(457		)	25			(527		)	(120		)
Other income, net	(48		)	—			(40		)	—
Income before income taxes	6,249			7,252			18,577			18,351
Benefit from income taxes	(178		)	(5,579		)	(1,427		)	(1,865		)
Net income	$	6,427		$	12,831		$	20,004		$	20,216
Net income attributable to limited partner interests	$	6,258		$	12,575		$	19,523		$	19,813
Net income per common unit (basic and diluted)	$	0.24		$	0.49		$	0.82		$	0.89
Weighted average common units outstanding	19,538			14,182			17,380			13,760
Net income per subordinated unit (basic and diluted)	$	0.24		$	0.49		$	0.80		$	0.85
Weighted average subordinated units outstanding	6,278			8,371			6,661			8,768

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(unaudited; in thousands)
Net income	$	6,427	$	12,831		$	20,004	$	20,216
Other comprehensive income (loss) — foreign currency translation	1,660		(105		)	3,159		675
Comprehensive income	$	8,087	$	12,726		$	23,163	$	20,891

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Nine Months Ended September 30,
	2017			2016
	(unaudited; in thousands)
Cash flows from operating activities:
Net income	$	20,004		$	20,216
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,164			14,725
Loss associated with derivative instruments	1,279			921
Settlement of derivative contracts	242			1,640
Unit based compensation expense	2,962			2,824
Other	750			648
Changes in operating assets and liabilities:
Accounts receivable	267			168
Accounts receivable — related party	(224		)	67
Prepaid expenses and other current assets	1,819			(3,037		)
Accounts payable and accrued expenses	990			(1,377		)
Accounts payable and accrued expenses — related party	(43		)	1,467
Deferred revenue and other liabilities	(6,733		)	2,284
Deferred revenue — related party	1,066			(2,783		)
Change in restricted cash	685			(664		)
Net cash provided by operating activities	38,228			37,099
Cash flows from investing activities:
Additions of property and equipment	(26,708		)	(471		)
Net cash used in investing activities	(26,708		)	(471		)
Cash flows from financing activities:
Distributions	(25,532		)	(21,943		)
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	44,000			15,000
Repayments of long-term debt	(66,342		)	(30,831		)
Net cash used in financing activities	(15,246		)	(37,851		)
Effect of exchange rates on cash	(148		)	559
Net change in cash and cash equivalents	(3,874		)	(664		)
Cash and cash equivalents – beginning of period	11,705			10,500
Cash and cash equivalents – end of period	$	7,831		$	9,836

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

USD PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	September 30, 2017			December 31, 2016
	(unaudited; in thousands, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	7,831		$	11,705
Restricted cash	5,138			5,433
Accounts receivable, net	4,168			4,321
Accounts receivable — related party	438			219
Prepaid expenses	8,717			10,325
Other current assets	3,178			2,562
Total current assets	29,470			34,565
Property and equipment, net	150,207			125,702
Intangible assets, net	102,464			111,919
Goodwill	33,589			33,589
Other non-current assets	180			192
Total assets	$	315,910		$	305,967

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and accrued expenses	$	3,555		$	2,221
Accounts payable and accrued expenses — related party	210			214
Deferred revenue, current portion	22,991			26,928
Deferred revenue, current portion — related party	5,710			4,292
Other current liabilities	3,189			3,513
Total current liabilities	35,655			37,168
Long-term debt, net	199,411			220,894
Deferred revenue, net of current portion	—			264
Deferred income tax liability, net	957			823
Total liabilities	236,023			259,149
Commitments and contingencies
Partners’ capital
Common units (19,537,699 and 14,185,599 outstanding at September 30, 2017 and December 31, 2016, respectively)	135,609			122,802
Class A units (82,500 and 138,750 outstanding at September 30, 2017 and December 31, 2016, respectively)	1,284			1,811
Subordinated units (6,278,127 and 8,370,836 outstanding at September 30, 2017 and December 31, 2016, respectively)	(59,066		)	(76,749		)
General partner units (461,136 outstanding at September 30, 2017 and December 31, 2016)	58			111
Accumulated other comprehensive income (loss)	2,002			(1,157		)
Total partners’ capital	79,887			46,818
Total liabilities and partners’ capital	$	315,910		$	305,967

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

USD PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL



	Nine Months Ended September 30,
	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	—		14,143			—		12,220
Unit based compensation expense	—		2,677			—		1,805
Distributions	—		(17,594		)	—		(12,778		)
Ending balance	19,537,699		135,609			14,181,996		124,244
Class A units
Beginning balance	138,750		1,811			185,000		1,749
Conversion of units	(46,250	)	(606		)	(46,250	)	(871		)
Net income	—		79			—		125
Unit based compensation expense	—		356			—		782
Forfeited units	(10,000	)	(247		)	—		—
Distributions	—		(109		)	—		(146		)
Ending balance	82,500		1,284			138,750		1,639
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	—		5,301			—		7,468
Unit based compensation expense	—		23			—		—
Distributions	—		(7,294		)	—		(8,581		)
Ending balance	6,278,127		(59,066		)	8,370,836		(75,387		)
General Partner units
Beginning balance	461,136		111			461,136		220
Net income	—		481			—		403
Unit based compensation expense	—		1			—		—
Distributions	—		(535		)	—		(438		)
Ending balance	461,136		58			461,136		185
Accumulated other comprehensive income (loss)
Beginning balance			(1,157		)			(138		)
Cumulative translation adjustment			3,159					675
Ending balance			2,002					537
Total partners’ capital at September 30,			$	79,887				$	51,218

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 oil 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 September 30, 2017, our results of operations for the three and nine months ended September 30, 2017 and 2016, and our cash flows for the nine months ended September 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 nine months ended September 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 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 September 30, 2017
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	4,721		$	1,517		$	20		$	169		$	6,427
Less: Distributable earnings ⁽²⁾	7,030			2,260			29			223			9,542
Distributions in excess of earnings	$	(2,309	)	$	(743	)	$	(9	)	$	(54	)	$	(3,115	)
Weighted average units outstanding ⁽³⁾	19,538			6,278			84			461			26,361
Distributable earnings per unit ⁽⁴⁾	$	0.36		$	0.36		$	0.35
Overdistributed earnings per unit ⁽⁵⁾	(0.12		)	(0.12		)	(0.11		)
Net income per limited partner unit (basic and diluted)	$	0.24		$	0.24		$	0.24


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $57 thousand attributed to the general partner for its incentive distribution rights

⁽²⁾

Represents the distributions payable for the period based upon the quarterly distribution amount of $0.345 per unit, or $1.38 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $392 thousand 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 September 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⁾	$	7,859	$	4,639	$	77	$	256	$	12,831
Less: Distributable earnings ⁽²⁾	4,733		2,792		46		154		7,725
Excess net income	$	3,126	$	1,847	$	31	$	102	$	5,106
Weighted average units outstanding ⁽³⁾	14,182		8,371		139		461		23,153
Distributable earnings per unit ⁽⁴⁾	$	0.33	$	0.33	$	0.33
Undistributed earnings per unit ⁽⁵⁾	0.16		0.16		0.16
Net income per limited partner unit (basic and diluted)	$	0.49	$	0.49	$	0.49


⁽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 $0.3225 per unit, or $1.29 per unit on an annualized basis. Amounts presented for each class of units include a proportionate amount of the $257 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 additional amount per unit necessary to distribute the excess net income for the period among our limited partners, our general partner and the holder of the IDRs according to the distribution formula for available cash as set forth in our partnership agreement.



	Nine Months Ended September 30, 2017
	Common Units			Subordinated Units			Class A Units			General Partner Units			Total
	(in thousands, except per unit amounts)
Net income attributable to general and limited partner interests in USD Partners LP ⁽¹⁾	$	14,143		$	5,301		$	79		$	481		$	20,004
Less: Distributable earnings ⁽²⁾	19,782			6,697			91			600			27,170
Distributions in excess of earnings	$	(5,639	)	$	(1,396	)	$	(12	)	$	(119	)	$	(7,166	)
Weighted average units outstanding ⁽³⁾	17,380			6,661			98			461			24,600
Distributable earnings per unit ⁽⁴⁾	$	1.14		$	1.01		$	0.93
Overdistributed earnings per unit ⁽⁵⁾	(0.32		)	(0.21		)	(0.12		)
Net income per limited partner unit (basic and diluted)	$	0.82		$	0.80		$	0.81


⁽¹⁾	Represents net income allocated to each class of units based on the actual ownership of the Partnership during the period. The net income for each class of limited partner interest has been reduced by its proportionate amount of the approximate $109 thousand attributed to the general partner for its incentive distribution rights.

⁽²⁾

Represents the per unit distributions paid of $0.335 per unit for the three months ended March 31, 2017, $0.34 per unit for the three months ended June 30, 2017, and $0.345 per unit distributable for the three months ended September 30, 2017, representing a year-to-date distribution amount of $1.02 per unit. Amounts presented for each class of units include a proportionate amount of the $785 thousand distributed and $392 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.



	Nine Months Ended September 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⁾	$	12,220		$	7,468		$	125		$	403		$	20,216
Less: Distributable earnings ⁽²⁾	13,867			8,183			135			451			22,636
Distributions in excess of earnings	$	(1,647	)	$	(715	)	$	(10	)	$	(48	)	$	(2,420	)
Weighted average units outstanding ⁽³⁾	13,760			8,768			148			461			23,137
Distributable earnings per unit ⁽⁴⁾	$	1.01		$	0.93		$	0.91
Overdistributed earnings per unit ⁽⁵⁾	(0.12		)	(0.08		)	(0.07		)
Net income per limited partner unit (basic and diluted)	$	0.89		$	0.85		$	0.84


⁽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, $0.315 per unit for the three months ended June 30, 2016, and $0.3225 per unit for the three months ended September 30, 2016, representing a year-to-date distribution amount of $0.945 per unit. Amounts presented for each class of units include a proportionate amount of the $756 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:



	September 30, 2017			December 31, 2016			Estimated Depreciable Lives (Years)
	(in thousands)						Estimated Depreciable Lives (Years)
Land	$	10,264		$	9,636		N/A
Trackage and facilities	128,475			108,782			10-30
Pipeline	16,105			10,313			20-25
Equipment	12,576			8,234			3-10
Furniture	68			44			5-10
Total property and equipment	167,488			137,009
Accumulated depreciation	(20,322		)	(13,821		)
Construction in progress	3,041			2,514
Property and equipment, net	$	150,207		$	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. In connection with the transaction, we also purchased approximately $1.4 million of crude oil used by the prior owner for line fill and tank bottoms and capitalized approximately $1.3 million of one-time costs.

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. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Our goodwill originated from our acquisition of the Casper terminal, which is included in our Terminalling services segment. As of September 30, 2017, the carrying amount of our goodwill was $33.6 million.

We test goodwill for impairment annually based on the carrying values of our reporting units on the first day of the third quarter of each year or more frequently if events or changes in circumstances suggest that the fair value of a reporting unit is less than its carrying value. During the third quarter of 2017, we completed our annual goodwill impairment analysis and determined that the fair value of the Casper terminal reporting unit exceeded its carrying value at July 1, 2017. An impairment charge would have resulted if our estimate of the fair value of the Casper terminal reporting unit was approximately 5% less than the amount determined. The critical assumptions used in our analysis include the following:


(1)	A weighted average cost of capital of 10.5%;


(2)	A capital structure consisting of approximately 35% debt and 65% equity;


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


(4)	A range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 8.25x to 9.25x.

We measured the fair value of our Casper terminal reporting unit by using an income analysis, market analysis and transaction analysis with weightings of 50%, 25% and 25%, respectively. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our Casper terminal. We have not observed any events or circumstances subsequent to our analysis that would suggest the fair value of our Casper terminal is below its carrying amount as of September 30, 2017.

Intangible Assets

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



	September 30, 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	(23,582		)	(14,135		)
Other	(20		)	(12		)
Total accumulated amortization	(23,602		)	(14,147		)
Total intangible assets, net	$	102,464		$	111,919

We determined the expiration of a customer contract for terminal services at our Casper terminal was an event that required us to evaluate our Casper terminal asset group for impairment. Our projections of the undiscounted cash

flows expected to be derived from the operation and disposition of the Casper terminal asset group exceeded the carrying value of the asset group as of August 31, 2017, the date of our evaluation, indicating cash flows were expected to be sufficient to recover the carrying value of the Casper terminal asset group.

Amortization expense associated with intangible assets totaled approximately $3.2 million for the three months ended September 30, 2017 and 2016, respectively, and $9.5 million for the nine months ended September 30, 2017 and 2016, respectively.

5. DEBT

We have a senior secured credit agreement, the Credit Agreement, comprised of a $400 million revolving credit facility (subject to the limits set forth therein), the Revolving Credit Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Agreement is a five year committed facility that matures on October 15, 2019.

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

Our Revolving Credit Facility and issuances of letters of credit are available for working capital, capital expenditures, permitted acquisitions and general partnership purposes, including distributions. We have the ability to increase the maximum amount of credit available under the Credit Agreement, as amended, by an aggregate amount of up to $100 million to a total facility size of $500 million, subject to receiving increased commitments from lenders or other financial institutions and satisfaction of certain conditions. The Revolving Credit Facility includes an aggregate $20 million sublimit for standby letters of credit and a $20 million sublimit for swingline loans. Obligations under the Revolving Credit Facility are guaranteed by our restricted subsidiaries (as such term is defined in our senior secured credit facility) and are secured by a first priority lien on our assets and those of our restricted subsidiaries, other than certain excluded assets.

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



	September 30, 2017			December 31, 2016
	(in thousands)
Term Loan Facility	$	—		$	10,128
Revolving Credit Facility	201,000			213,000
Less: Deferred financing costs, net	(1,589		)	(2,234		)
Total long-term debt, net	$	199,411		$	220,894

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



	September 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	201.0		213.0
Letters of credit outstanding	—		—
Available under Credit Agreement ⁽¹⁾	$	199.0	$	176.9

⁽¹⁾

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.

The average interest rate on our outstanding indebtedness was 3.82% and 3.66% at September 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 September 30, 2017, we were in compliance with the covenants set forth in our Credit Agreement.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Interest expense on the Credit Agreement	$	2,172	$	2,356	$	6,862	$	6,642
Amortization of deferred financing costs	216		216		646		646
Total interest expense	$	2,388	$	2,572	$	7,508	$	7,288

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 revenue 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 from unrelated customers as reflected in our consolidated balance sheets as of the dates indicated:



	September 30, 2017		December 31, 2016
	(in thousands)
Customer prepayments, current portion ⁽¹⁾	$	856	$	3,705
Minimum monthly commitment fees	22,135		23,223
Total deferred revenue, current portion	$	22,991	$	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 $6.4 million and $5.5 million of expenses for the three months ended September 30, 2017 and 2016, respectively, and $17.2 million and $15.5 million for the nine months ended September 30, 2017 and 2016, respectively, which are presented as “Pipeline fees” in our consolidated statements of income. Additionally, at September 30, 2017 and December 31, 2016, we had prepaid pipeline fees of $7.0 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 September 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 revenue.



	September 30, 2017
	Total assets		Total liabilities		Maximum exposure to loss
	(in thousands)
Accounts receivable	20		$	—	$	—
Accounts payable	—		—		—
Deferred revenue, current portion	—		603		—
Deferred revenue, net of current portion	—		—		—
	$	20	$	603	$	—



	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 September 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 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 Marketing LLC, or USDM, is a wholly-owned subsidiary of USDG, organized to facilitate terminalling services at our terminals.

USD Partners GP LLC, our general partner, currently owns all 461,136 of our general partner units representing a 1.7% general partner interest in us, as well as all of our incentive distribution rights. Pursuant to our partnership agreement, our general partner is responsible for our overall governance and operations.

Omnibus Agreement

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

The total amounts charged to us under the omnibus agreement for the three months ended September 30, 2017 and 2016, were $1.5 million and $1.4 million, respectively, and for the nine months ended September 30, 2017 and 2016, were $4.3 million and $4.4 million, respectively, which amounts are included in “Selling, general and administrative — related party” in our consolidated statements of income. At both September 30, 2017 and December 31, 2016, we had balances payable related to these costs of $0.2 million, 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 no significant balances payable or receivable at September 30, 2017, 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 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Fleet services — related party	$	—	$	—	$	—	$	810

Related Party Revenue and Deferred Revenue

We have agreements to provide USDM 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 a former third-party customer, effective as of June 1, 2017, to facilitate the origination of crude oil barrels from our Hardisty terminal by the Stroud terminal customer 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Terminalling services — related party	$	4,716	$	1,736	$	8,974	$	5,142
Fleet leases — related party	1,013		890		2,794		2,671
Fleet services — related party	218		279		776		837
Freight and other reimbursables — related party	—		—		1		—
	$	5,947	$	2,905	$	12,545	$	8,650

We had $0.4 million receivable from USDM as of September 30, 2017, and no receivables at 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 as of the indicated dates:



	September 30, 2017		December 31, 2016
	(in thousands)
Customer prepayments, current portion ⁽¹⁾	$	411	$	390
Minimum monthly commitment fees	5,299		3,902
Total deferred revenue, current portion	$	5,710	$	4,292


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

Cash Distributions

During the nine months ended September 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 and as the holder of our IDRs.



Distribution Declaration Date	Record Date	Distribution Payment Date	Amount Paid to USDG		Amount Paid to USD Partners GP LLC
			(in thousands)
February 1, 2017	February 13, 2017	February 17, 2017	$	3,814	$	152
April 27, 2017	May 8, 2017	May 12, 2017	3,872		170
July 27, 2017	August 7, 2017	August 11, 2017	3,929		194
			$	11,615	$	516

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 nine months ended September 30, 2016.

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 formation 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 they are included to present shared services and financing activities that 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 September 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	21,799		$	—	$	—		$	21,799
Terminalling services — related party	4,716			—		—			4,716
Railroad incentives	4			—		—			4
Fleet leases	—			643		—			643
Fleet leases — related party	—			1,013		—			1,013
Fleet services	—			470		—			470
Fleet services — related party	—			218		—			218
Freight and other reimbursables	—			118		—			118
Freight and other reimbursables — related party	—			—		—			—
Total revenues	26,519			2,462		—			28,981
Operating costs
Subcontracted rail services	2,340			—		—			2,340
Pipeline fees	6,367			—		—			6,367
Fleet leases	—			1,656		—			1,656
Freight and other reimbursables	—			118		—			118
Operating and maintenance	654			95		—			749
Selling, general and administrative	1,395			210		2,093			3,698
Depreciation and amortization	5,254			—		—			5,254
Total operating costs	16,010			2,079		2,093			20,182
Operating income (loss)	10,509			383		(2,093		)	8,799
Interest expense	—			—		2,388			2,388
Loss associated with derivative instruments	667			—		—			667
Foreign currency transaction loss (gain)	(20		)	4		(441		)	(457		)
Other income, net	(48		)	—		—			(48		)
Provision for (benefit from) income taxes	(343		)	196		(31		)	(178		)
Net income (loss)	$	10,253		$	183	$	(4,009	)	$	6,427



	Three Months Ended September 30, 2016
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	24,078		$	—		$	—		$	24,078
Terminalling services — related party	1,736			—			—			1,736
Railroad incentives	24			—			—			24
Fleet leases	—			643			—			643
Fleet leases — related party	—			890			—			890
Fleet services	—			475			—			475
Fleet services — related party	—			279			—			279
Freight and other reimbursables	—			218			—			218
Freight and other reimbursables — related party	—			—			—			—
Total revenues	25,838			2,505			—			28,343
Operating costs
Subcontracted rail services	2,004			—			—			2,004
Pipeline fees	5,492			—			—			5,492
Fleet leases	—			1,534			—			1,534
Freight and other reimbursables	—			218			—			218
Operating and maintenance	651			95			—			746
Selling, general and administrative	1,258			230			2,455			3,943
Depreciation and amortization	4,906			—			—			4,906
Total operating costs	14,311			2,077			2,455			18,843
Operating income (loss)	11,527			428			(2,455		)	9,500
Interest expense	286			—			2,286			2,572
Gain associated with derivative instruments	(349		)	—			—			(349		)
Foreign currency transaction loss (gain)	31			(2		)	(4		)	25
Other income, net	—			—			—			—
Provision for (benefit from) income taxes	(5,739		)	160			—			(5,579		)
Net income (loss)	$	17,298		$	270		$	(4,737	)	$	12,831



	Nine Months Ended September 30, 2017
	Terminalling services			Fleet services		Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	67,335		$	—	$	—		$	67,335
Terminalling services — related party	8,974			—		—			8,974
Railroad incentives	25			—		—			25
Fleet leases	—			1,929		—			1,929
Fleet leases — related party	—			2,794		—			2,794
Fleet services	—			1,405		—			1,405
Fleet services — related party	—			776		—			776
Freight and other reimbursables	110			373		—			483
Freight and other reimbursables — related party	—			1		—			1
Total revenues	76,444			7,278		—			83,722
Operating costs
Subcontracted rail services	6,148			—		—			6,148
Pipeline fees	17,153			—		—			17,153
Fleet leases	—			4,723		—			4,723
Freight and other reimbursables	110			374		—			484
Operating and maintenance	1,765			285		—			2,050
Selling, general and administrative	3,795			694		6,714			11,203
Depreciation and amortization	15,164			—		—			15,164
Total operating costs	44,135			6,076		6,714			56,925
Operating income (loss)	32,309			1,202		(6,714		)	26,797
Interest expense	170			—		7,338			7,508
Loss associated with derivative instruments	1,279			—		—			1,279
Foreign currency transaction loss (gain)	(33		)	6		(500		)	(527		)
Other income, net	(40		)	—		—			(40		)
Provision for (benefit from) income taxes	(1,761		)	511		(177		)	(1,427		)
Net income (loss)	$	32,694		$	685	$	(13,375	)	$	20,004
Goodwill	$	33,589		$	—	$	—		$	33,589
Total assets	$	312,970		$	2,001	$	939		$	315,910
Capital expenditures	$	26,708		$	—	$	—		$	26,708



	Nine Months Ended September 30, 2016
	Terminalling services			Fleet services			Corporate			Total
	(in thousands)
Revenues
Terminalling services	$	69,560		$	—		$	—		$	69,560
Terminalling services — related party	5,142			—			—			5,142
Railroad incentives	61			—			—			61
Fleet leases	—			1,933			—			1,933
Fleet leases — related party	—			2,671			—			2,671
Fleet services	—			613			—			613
Fleet services — related party	—			1,647			—			1,647
Freight and other reimbursables	12			932			—			944
Freight and other reimbursables — related party	—			—			—			—
Total revenues	74,775			7,796			—			82,571
Operating costs
Subcontracted rail services	6,073			—			—			6,073
Pipeline fees	15,544			—			—			15,544
Fleet leases	—			4,605			—			4,605
Freight and other reimbursables	12			932			—			944
Operating and maintenance	2,158			241			—			2,399
Selling, general and administrative	3,548			631			7,662			11,841
Depreciation and amortization	14,725			—			—			14,725
Total operating costs	42,060			6,409			7,662			56,131
Operating income (loss)	32,715			1,387			(7,662		)	26,440
Interest expense	968			—			6,320			7,288
Loss associated with derivative instruments	921			—			—			921
Foreign currency transaction gain	(44		)	(72		)	(4		)	(120		)
Other income, net	—			—			—			—
Provision for (benefit from) income taxes	(2,008		)	142			1			(1,865		)
Net income (loss)	$	32,878		$	1,317		$	(13,979	)	$	20,216
Goodwill	$	33,970		$	—		$	—		$	33,970
Total assets	$	309,357		$	5,754		$	1,951		$	317,062
Capital expenditures	$	471		$	—		$	—		$	471

Segment Adjusted EBITDA

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	14,186		$	17,080		$	46,434		$	50,310
Fleet services	383			428			1,202			1,387
Corporate activities ⁽¹⁾	(1,147		)	(1,328		)	(3,752		)	(4,838		)
Total Adjusted EBITDA	13,422			16,180			43,884			46,859
Add (deduct):
Amortization of deferred financing costs	216			216			646			646
Deferred income taxes	(221		)	98			86			2
Changes in accounts receivable and other assets	3,215			(4,309		)	1,862			(2,802		)
Changes in accounts payable and accrued expenses	2,033			2,027			947			90
Changes in deferred revenue and other liabilities	(3,147		)	(2,599		)	(5,667		)	(499		)
Change in restricted cash	915			(31		)	685			(664		)
Interest expense, net	(2,384		)	(2,572		)	(7,500		)	(7,288		)
Benefit from income taxes	178			5,579			1,427			1,865
Foreign currency transaction gain (loss) ⁽²⁾	457			(25		)	527			120
Deferred revenue associated with minimum monthly commitment fees ⁽³⁾	1,473			(43		)	1,331			(1,230		)
Net cash provided by operating activities	$	16,157		$	14,521		$	38,228		$	37,099


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


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

⁽³⁾

Represents 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 Revenue 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 $0.9 million and $1.9 million for the three and nine months ended September 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. We had taxable income of $0.4 million and a net operating loss of $0.8 million for the three and nine months ended September 30, 2016, respectively, and as a result of the year-to-date loss, 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 nine months ended September 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 received of approximately $2.6 million (C$3.4 million) in connection with our Canadian federal and provincial income tax returns for 2016, which we filed in June 2017. In 2016, we adopted a methodology for determining the return attributable to our Canadian subsidiaries based upon the 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. This methodology also resulted in a reduction of our Canadian income tax liability for the 2015 tax year, which we reflected in our third quarter 2016 income statement as a benefit to our 2016 income taxes.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Current income tax expense (benefit):
U.S. federal income tax	$	289		$	—		$	662		$	—
U.S. federal operating loss carryforward	56			—			(200		)	—
State income tax expense (benefit)	(17		)	14			(126		)	44
Canadian federal and provincial income taxes benefit	(285		)	(5,691		)	(1,849		)	(1,911		)
Total current income tax expense (benefit)	43			(5,677		)	(1,513		)	(1,867		)
Deferred income tax expense (benefit):
U.S. federal income tax expense (benefit)	(164		)	147			10			147
Canadian federal and provincial income taxes expense (benefit)	(57		)	(49		)	76			(145		)
Total change in deferred income tax expense (benefit)	(221		)	98			86			2
Benefit from income taxes	$	(178	)	$	(5,579	)	$	(1,427	)	$	(1,865	)

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Income tax expense at the U.S. federal statutory rate	$	2,124		$	2,465		$	6,316		$	6,239
Amount attributable to partnership not subject to income tax	(2,418		)	(9,477		)	(8,132		)	(8,318		)
Foreign income tax rate differential	91			1,668			456			709
Other	27			45			38			(17		)
State income tax expense (benefit) ⁽¹⁾	(21		)	14			(139		)	44
Change in valuation allowance	19			(294		)	34			(522		)
Benefit from income taxes	$	(178	)	$	(5,579	)	$	(1,427	)	$	(1,865	)


⁽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:



	September 30, 2017
	U.S.			Foreign			Total
	(in thousands)
Deferred income tax assets
Deferred revenues	$	—		$	—		$	—
Capital loss carryforwards	—			472			472
Operating loss carryforwards	—			—			—
Deferred income tax liabilities
Unbilled revenue	—			(285		)	(285		)
Prepaid expenses	(256		)	—			(256		)
Property and equipment	—			(416		)	(416		)
Valuation allowance	—			(472		)	(472		)
Deferred income tax liability, net	$	(256	)	$	(701	)	$	(957	)



	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 September 30, 2017, and approximately $0.8 million as of December 31, 2016. Our available Canadian loss carryforward was approximately $4.7 million and $4.4 million as of September 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 before our formation. We did not have any unrecognized income tax benefits or any income tax reserves for uncertain tax positions as of September 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 September 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 at the Stroud terminal. We agreed to sell the approximately 18,000 barrels, or bbl, of crude oil used for tank bottoms in July 2017, and the approximately 13,000 bbl of crude oil used for line fill in October 2017, to an unrelated party at a price which varies with the price of crude oil during the months of July and October of 2017. In June 2017, we entered into two separate fixed-for-floating swap contracts with an aggregate notional amount of 31,778 bbl, to manage our exposure to fluctuating crude oil prices. Each swap contract effectively fixes the price we will receive upon our delivery of the crude oil. The first contract for approximately 18,000 bbl settled in July 2017 at $47.20 per barrel and the second for approximately 13,000 bbl will settle in October 2017 at $47.70 per barrel.

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

Derivative Positions

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



	September 30, 2017			December 31, 2016
	(in thousands)
Other current assets	$	—		$	1,167
Other current liabilities	(354		)	—
	$	(354	)	$	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 September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(in thousands)
Loss (gain) associated with derivative instruments	$	667	$	(349	)	$	1,279	$	921

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 September 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	—	—			290
December 29, 2017	C$	8,400,000	0.7809	0.8028	(184		)	282
Total					$	(184	)	$	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 September 30, 2017.



	At September 30, 2017
	Notional	Market Price ⁽¹⁾		Fixed Price ⁽²⁾		Fair Value
	(in Bbl)					(in thousands)
Commodity swaps maturing in 2017
July 2017 ⁽³⁾	18,395	$	—	$	47.20	$	—
October 2017	13,383	$	51.76	$	47.70	(54		)
October 2017	30,000	$	51.76	$	47.90	(116		)
	61,778					$	(170	)


⁽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 September 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.


⁽³⁾	The market price for the commodity swap on July 14, 2017, the date we sold the crude oil, was $47.64.

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 assets associated with our derivative contracts at September 30, 2017, or liabilities at December 31, 2016, that were offset against the asset and liability 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 with respect to our common units (excluding any arrearages of unpaid minimum quarterly distributions from prior quarters) and, as a result, are considered participating securities. Our Class A units do not have voting rights and vest in four equal annual installments over the four years following the consummation of our initial public offering, or IPO, only if we grow our annualized distributions each year. If we do not achieve

positive distribution growth in any of these years, the Class A units that would otherwise vest for that year will be forfeited. The Class A units contain a conversion feature, which, upon vesting, provides for the conversion of the Class A units into common units based on a conversion factor that is tied to the level of our distribution growth for the applicable year. The conversion factor was 1.00 for the first vesting tranche, 1.50 for the second vesting tranche 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 nine months 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 are 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 September 30, 2017 and 2016.

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



	Nine Months Ended September 30,
	2017		2016
Class A units outstanding at beginning of period	138,750		185,000
Vested	(46,250	)	(46,250	)
Forfeited	(10,000	)	—
Class A units outstanding at end of period	82,500		138,750

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2017			2016		2017		2016
	(in thousands)
Selling, general and administrative ⁽¹⁾	$	(124	)	$	248	$	108	$	782

⁽¹⁾Includes $247 thousand reduction to compensation expense for Class A forfeitures for the three and nine months ended September 30, 2017.

For the three and nine months ended September 30, 2017, we had forfeitures of 10,000 Class A units. No forfeitures occurred during the three and nine months ended September 30, 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 we determine that the Class A units are not expected to vest. For the three and nine months ended September 30, 2017, we recognized compensation expense of $30 thousand for distributions paid on Class A units that were forfeited during the periods. For the three and nine months ended September 30, 2016, we recognized no amounts in compensation expense for distributions paid on forfeited Class A units.

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 693,099 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 177,952 remained available at September 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 and an independent consultant 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		639,955		$	12.79
Vested	(64,830	)	(204,456	)	$	8.47
Forfeited	—		(56,083	)	$	10.94
Phantom Unit awards at September 30, 2017	24,999		1,110,224		$	10.91



	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
Forfeited	—		(2,608	)	$	7.97
Phantom Unit awards at September 30, 2016	68,433		731,280		$	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 September 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 September 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 September 30, 2017 and 2016, we recognized approximately $1.1 million and $0.9 million, respectively, of compensation expense associated with outstanding Phantom Units, and for the nine months ended September 30, 2017 and 2016, we recognized approximately $2.9 million and $2.0 million, respectively. As of September 30, 2017, we have unrecognized compensation expense associated with our outstanding Phantom Units totaling $10.3 million, which we expect to recognize over a weighted average period of 2.87 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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Equity-classified Phantom Units ⁽¹⁾	$	388	$	252	$	1,048	$	612
Liability-classified Phantom Units	17		16		48		39
Total	$	405	$	268	$	1,096	$	651


⁽¹⁾	We reclassified $61 thousand and $2 thousand for the three months ended September 30, 2017 and 2016, and $64 thousand and $2 thousand for the nine months ended September 30, 2017 and 2016, respectively, to unit based compensation expense for DERs paid in relation to Phantom Units that have been forfeited.

16. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Cash paid (received) for income taxes	$	(1,250	)	$	2,160
Cash paid for interest	$	7,102		$	6,558

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



	Nine Months Ended September 30,
	2017		2016
	(in thousands)
Loss associated with disposal of assets	$	18	$	—
Amortization of deferred financing costs	646		646
Deferred income taxes	86		2
	$	750	$	648

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. However, any

impairment assessment we perform subsequent to our adoption of the standard could produce an impairment of goodwill to the extent the carrying amount of a reporting unit exceeds its fair value.

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.

Currently, we cannot reasonably estimate the impact our adoption of ASU 2016-02 will 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 agreement 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 other related 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 assessed the impact our adoption of ASU 2014-09 is expected to have on our current accounting policies, which we have modified to incorporate the requirements of the new standard. We have completed our evaluation and modification of existing accounting policies although further refinement may be necessary. We have developed financial models to permit quantifying the impact our application of ASU 2014-09 will have on our previously issued financial

statements and are currently in the process of quantifying the impact our adoption will have on previously issued financial statements. We have prepared drafts of disclosures required by the new standard, which we are refining in connection with quantifying the impact to previously issued financial statements. We are also evaluating our processes and controls to identify any enhancements necessary to ensure we properly account for revenue from contracts with customers and accumulate the information necessary to adequately disclose such data as required by ASU 2014-09. 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.

We currently expect to adopt ASU 2014-09 by applying the full retrospective transition method. The most significant policy revision we have identified 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 requires 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 rights provisions granted to customers of our Hardisty terminal, which are discussed below. 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 and the related disclosures we expect to be affected by our application of the requirements of ASU 2014-09, based upon modifications of our accounting policies. 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 rights options has approximated 100%, which will result in our recognizing all or a portion 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. Our implementation of these changes will affect our existing accounting policy disclosures. Additionally, our revenue and deferred revenue disclosures will be revised to include the periods that the remaining performance obligations will be recognized, as well as disclosure of the breakage rates associated with the make-up right options.

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 recognition of a portion of the previously deferred revenue, we will concurrently recognize a proportionate amount of the prepaid pipeline fees as expense in connection with our adoption of ASU 2014-09. Our implementation of these changes will also affect the disclosures we make regarding amounts associated with our collaborative arrangement with Gibson.

Provision for Income Taxes and Non-current Deferred Income Tax Liability — As a result of the increases in “Terminalling services revenue” and “Pipeline fees” as discussed above, our provision for income taxes and the related

non-current deferred income tax liability, as well as the related disclosures thereof, may increase due to the expected increases 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, 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 October 26, 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 $0.345 per unit, or $1.38 per unit on an annualized basis, for the three months ended September 30, 2017. The distribution represents an increase of $0.005 per unit, or 1.5% over the prior quarter distribution per unit, and is 20.0% over our minimum quarterly distribution per unit. The distribution will be paid on November 13, 2017, to unitholders of record at the close of business on November 6, 2017. The distribution will include payment of $4.9 million to our public common unitholders, $28 thousand to the Class A unitholders, an aggregate of $4.0 million to USDG as a holder of our common units and the sole owner of our subordinated units and $216 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 and subsequent Quarterly Reports on Form 10-Q. Please also read the “Cautionary Note Regarding Forward-Looking Statements” following the table of contents in this Report.

Throughout the following discussion we denote amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.

Overview

We are a fee-based, growth-oriented master limited partnership formed by 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 oil 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 U.S. Gulf Coast and Mexico. Among other projects, USDG is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities.

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 on-site 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 purchased approximately $1.4 million of crude oil used by the prior owner for line fill and tank bottoms at the Stroud terminal. In September 2017, we purchased an additional $1.3 million of crude oil used by the prior owner as tank bottoms for a storage tank lease at the Cushing hub we assumed in connection with the purchase of the Stroud terminal. We expect to sell all of the crude oil we purchased before the end of the 2017. Additionally, we capitalized approximately $1.3 million of one-time transaction costs in connection with our purchase of the Stroud terminal. During 2017, we spent 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 began on October 1, 2017, and runs through 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 the optionality provided by established connectivity from Cushing to multiple refining centers across the U.S. 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

Our historical operations include 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 continue to explore opportunities to provide ethanol terminalling services to other potential customers in the San Antonio market.

Customer Contract Expirations and Renewals

At our Casper terminal, one of our terminalling services agreements expired in late August 2017. The expired agreement contributed approximately $15 million to our “Terminalling services” revenue and approximately $12 million of Adjusted EBITDA during the twelve months preceding expiration of the agreement. We continue to actively pursue commercial arrangements with current and potential new customers for the provision of terminalling services to utilize the available loading and storage capacity at the Casper terminal. We are also actively exploring the potential to establish a rail-to-pipeline solution at the Casper terminal, which would require additional capital investments for outbound pipeline connectivity and railcar unloading capabilities. However, we cannot make any assurances regarding the outcome or timing of these efforts, which may result in lower operating income at the Casper terminal for one or more quarters until commercial agreements and any related capital investments are in place.

As discussed in this Report, we continue to expect Western Canada crude oil production, including recent 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.

Railcar Lease Expirations

Under our master fleet services agreements, we provide customers with railcar-specific fleet services. 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. Through the end of 2018, we expect the leases on approximately 970 railcars to expire, approximately half of which relate to a legacy customer of a terminal sold prior to our formation and the remainder of which relate to a prior customer at our Hardisty terminal. We do not expect the expirations of these railcar leases to have a significant impact on our operating income or cash flows.

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 as 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, which decreased the supply of synthetic crude oil available to the market during the second and third quarters of 2017. With meaningful supply offline, spreads between WCS and other benchmarks tightened meaningfully over that period, reducing the volume of crude oil imported into the United States from Canada via rail. Recently, as Syncrude returns to normal operating conditions, spreads have widened, particularly with respect to the Mexican heavy crude oil alternative, Maya. As a result, throughput activity at our crude oil terminals reached two-year highs in the third quarter.

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.

Subsequent to June 2017, the following developments occurred which may not be reflected in CAPP’s projections:


•	In August 2017, Canadian Natural Resources Limited disclosed the targeted start-up of its 80,000 Bpd Horizon Phase 3 project during the fourth quarter of 2017 and planned efforts to achieve production levels in excess of nameplate capacity once Phase 3 is operational.

•

In September 2017, Suncor Energy Inc., or Suncor, disclosed the transitioning of the 194,000 Bpd Fort Hills project from the construction phase into commissioning and operations, with first oil expected by the end of 2017 and 90% of planned production levels expected to be reached within 12 months. Additionally, Suncor outlined a replication strategy for its next phase of growth, including approximately 10 phases of in situ production totaling over 360,000 Bpd beginning in 2022.

Furthermore, we expect the recent consolidation of Western Canadian oil sands production assets among active Canadian producers will drive further additions to crude oil production capacity, particularly at existing projects, as cost savings and technological advancements made during the recent commodity price downturn are incorporated into future development plans. For example, following the buyout of the remaining interest in its Foster Creek Christina Lake partnership from ConocoPhillips Company, Cenovus Energy Inc. 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 at 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 the optionality provided by established connectivity from Cushing to multiple refining centers across the U.S. Rail also generally provides a greater ability to preserve the specific quality of a customer's product relative to pipelines, providing value to a producer or refiner. We expect these advantages, including our recently established origin-to-destination capabilities, to 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 Bbl 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 the Enbridge 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, purchase date and began producing revenue upon the commencement of its terminalling services agreement on October 1, 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 3.3 years as of September 30, 2017. We do not own any railcars. As of September 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 September 30,						Nine Months Ended September 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	$	16,157		$	14,521		$	38,228		$	37,099
Add (deduct):
Amortization of deferred financing costs	(216		)	(216		)	(646		)	(646		)
Deferred income taxes	221			(98		)	(86		)	(2		)
Changes in accounts receivable and other assets	(3,215		)	4,309			(1,862		)	2,802
Changes in accounts payable and accrued expenses	(2,033		)	(2,027		)	(947		)	(90		)
Changes in deferred revenue and other liabilities	3,147			2,599			5,667			499
Change in restricted cash	(915		)	31			(685		)	664
Interest expense, net	2,384			2,572			7,500			7,288
Benefit from income taxes	(178		)	(5,579		)	(1,427		)	(1,865		)
Foreign currency transaction loss (gain) ⁽¹⁾	(457		)	25			(527		)	(120		)
Deferred revenue associated with minimum monthly commitment fees ⁽²⁾	(1,473		)	43			(1,331		)	1,230
Adjusted EBITDA	13,422			16,180			43,884			46,859
Add (deduct):
Cash received (paid) for income taxes ⁽³⁾	2,664			1,036			1,250			(2,160		)
Cash paid for interest	(2,165		)	(2,571		)	(7,102		)	(6,558		)
Maintenance capital expenditures	(274		)	(227		)	(472		)	(245		)
Distributable cash flow	$	13,647		$	14,418		$	37,560		$	37,896


⁽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 refund of $2.6 million (representing C$3.4 million) received in the three and nine months ended September 30, 2017, for our 2016 foreign income taxes. Also includes refunds of approximately $0.7 million (representing C$0.9 million) received in the nine months ended September 30, 2017, and approximately $1.4 million (representing C$1.8 million) received in the three and nine months ended September 30, 2016, for our 2015 foreign income taxes.

Operating Costs

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

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

Volumes

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


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


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


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

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, secure a minimum exchange rate of 0.78 U.S. dollars per Canadian dollar for our 2017 fiscal year and secured an exchange rate of 0.84 U.S. dollars per Canadian dollar during our 2016 fiscal year. The average exchange rates for the Canadian dollar in relation to the U.S. dollar were 0.7658 and 0.7573 for the nine months ended September 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 the 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 income tax liability for 2016 based upon the Canadian federal and provincial income tax returns for 2016 that we filed in June 2017, which resulted in refunds of approximately $2.6 million (C$3.4 million). We have 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Operating income (loss)
Terminalling services	$	10,509		$	11,527		$	32,309		$	32,715
Fleet services	383			428			1,202			1,387
Corporate and other	(2,093		)	(2,455		)	(6,714		)	(7,662		)
Total operating income	8,799			9,500			26,797			26,440
Interest expense	2,388			2,572			7,508			7,288
Loss (gain) associated with derivative instruments	667			(349		)	1,279			921
Foreign currency transaction loss (gain)	(457		)	25			(527		)	(120		)
Other income, net	(48		)	—			(40		)	—
Benefit from income taxes	(178		)	(5,579		)	(1,427		)	(1,865		)
Net income	$	6,427		$	12,831		$	20,004		$	20,216

Summary Analysis of Operating Results

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


•	increased terminalling services revenue associated with greater activity at the Hardisty terminal, as well as recognition of more previously deferred revenue in the current year relative to the prior year due to the expiration of greater amounts of make-up rights granted to customers of our Hardisty terminal;


•	terminalling services revenue reductions attributable to the discontinuation of operations at our San Antonio terminal in May 2017 following the conclusion of our customer's agreement with us and the expiration of one of our Casper terminalling services agreements in August, which partially offset the increased revenue from the Hardisty terminal;


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


•	decreased 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, which were recorded in 2017, as compared with revisions to the 2015 estimates recorded in 2016.

Although we acquired the Stroud terminal in June 2017 and began incurring related expenses in the second and third quarters of 2017, our customer contract commenced 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Revenues
Terminalling services	$	26,515		$	25,814		$	76,309		$	74,702
Railroad incentives	4			24			25			61
Freight and other reimbursables	—			—			110			12
Total revenues	26,519			25,838			76,444			74,775
Operating costs
Subcontracted rail services	2,340			2,004			6,148			6,073
Pipeline fees	6,367			5,492			17,153			15,544
Freight and other reimbursables	—			—			110			12
Operating and maintenance	654			651			1,765			2,158
Selling, general and administrative	1,395			1,258			3,795			3,548
Depreciation and amortization	5,254			4,906			15,164			14,725
Total operating costs	16,010			14,311			44,135			42,060
Operating income	10,509			11,527			32,309			32,715
Interest expense	—			286			170			968
Loss (gain) associated with derivative instruments	667			(349		)	1,279			921
Foreign currency transaction loss (gain)	(20		)	31			(33		)	(44		)
Other income, net	(48		)	—			(40		)	—
Benefit from income taxes	(343		)	(5,739		)	(1,761		)	(2,008		)
Net income	$	10,253		$	17,298		$	32,694		$	32,878
Average daily terminal throughput (bpd)	37,883			32,899			31,100			31,680

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

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $0.7 million to $26.5 million for the three months ended September 30, 2017. This increase was primarily due to increased activity by our customers at the Hardisty terminal. This increase was partially offset by decreased revenue at our San Antonio facility following the conclusion of our customer agreement in May 2017 and the expiration of a customer agreement at our Casper terminal in August 2017. Our agreement with Canadian Pacific Railway Limited for a per car incentive expired on June 30, 2017. As a result, we 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 $13.7 million of previously deferred revenues during the three months ended September 30, 2017, as compared with $13.0 million during the three months ended September 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 $0.8 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2017, was the same as the average exchange rate for the three months ended September 30, 2016.

Our Stroud terminal commenced operations on October 1, 2017, which we expect to generate additional revenues and operating costs in the fourth quarter of 2017.

Operating Costs

The operating costs of our Terminalling services segment increased $1.7 million to $16.0 million for the three months ended September 30, 2017, compared with $14.3 million for the three months ended September 30, 2016. This increase was primarily due to expenses at the Stroud terminal incurred in preparation for operations in October 2017. Additionally, increased utilization of our Hardisty terminal resulted in an increase in subcontracted rail services and pipeline fees at our Hardisty terminal. These expenses were partially offset by reduced costs associated with the discontinuation of operations at our San Antonio terminal.

Our terminalling services operating costs would have been approximately $0.3 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the three months ended September 30, 2017, was the same as the average exchange rate for the three months ended September 30, 2016.

Subcontracted rail services. Our subcontracted rail services costs increased $0.3 million to $2.3 million for the three months ended September 30, 2017, from $2.0 million for the three months ended September 30, 2016. This increase was primarily due to the addition of services at the Stroud terminal in preparation for the commencement of operations in October 2017, as well as increased activity at our Hardisty terminal. This was partially offset by the discontinuation of operations at our 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. Our pipeline fee costs increased $0.9 million to $6.4 million for the three months ended September 30, 2017, from $5.5 million for the three months ended September 30, 2016, primarily due to the increase in revenues recognized at the Hardisty terminal as discussed above.

Depreciation and amortization. Depreciation and amortization expense increased approximately $0.3 million to approximately $5.3 million for the three months ended September 30, 2017, primarily due to the additional depreciation expense associated with our Stroud terminal.

Other Expenses

Interest expense. We had no interest expense for our Terminalling services segment for the three months ended September 30, 2017, as compared with $0.3 million for the three months ended September 30, 2016, due to our repayment of all amounts outstanding on the Term Loan Facility in March 2017, which eliminated any future interest expense of our Terminalling Services business directly attributable to the Term Loan 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.

In June 2017, as a part of our purchase of the Stroud terminal and related facilities, we acquired crude oil used by the prior owner for line fill in the crude oil pipeline and tank bottoms for the storage tanks at the Stroud terminal. In September, we also acquired crude oil used for tank bottoms by the prior owner at our leased storage facility in Cushing, Oklahoma. We intend to sell all of this crude oil prior to the end of 2017. We entered into commodity swap contracts to fix the price we will receive upon our sale of the crude oil. Due to the change in fair value of these contracts from the date entered, we have experienced a non-cash loss of approximately $0.2 million for the three months ended September 30, 2017.

From June 30, 2017 to September 30, 2017, the exchange rate between the U.S. dollar and the Canadian dollar increased from a spot rate of 0.7703 to a spot rate of 0.8018 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our currency denominated derivative contracts maturing on or after September 30, 2017, relative to the value of these contracts at June 30, 2017, producing a non-cash loss of approximately $0.5 million for the three months ended September 30, 2017.

From June 30, 2016 to September 30, 2016, the exchange rate between the U.S. dollar and the Canadian dollar decreased from a spot rate of 0.7718 to a spot rate of 0.7609 U.S. dollars for each Canadian dollar, which slightly increased the value of our currency denominated derivative contracts maturing on or after September 30, 2016.

Benefit from income taxes. A significant amount of our operating income is generated by our Hardisty terminal located in the Canadian province of Alberta. As a Canadian business, operating income derived from our Hardisty terminal is subject to corporate income taxes assessed by the Canadian federal and provincial governments at enacted rates which currently total 27% on a combined basis.

Our benefit from income taxes for the Terminalling services segment decreased $5.4 million to $0.3 million for the three months ended September 30, 2017 as compared with a benefit of $5.7 million for the three months ended September 30, 2016. In 2016, we adopted a methodology for determining the appropriate return attributable to the activities of our foreign subsidiaries based on the functions we provide on their behalf. Our adoption of this methodology resulted in a reduction of our Canadian income tax liabilities for the 2015 and 2016 tax years, which we recorded during the three months ended September 30, 2016, producing a benefit from income taxes. We received refunds totaling approximately $2.6 million (C$3.4 million) associated with our 2016 tax year during the third quarter of 2017, which we reflected as a reduction to our “Provision for income taxes”, producing a benefit. For the three months ended September 30, 2017, we also reduced our estimates for 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. As such, we expect to pay minimal amounts of Canadian federal and provincial income taxes for the remainder of 2017 based on our revised estimates.

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Terminalling Services Revenue

Revenue generated by our Terminalling services segment increased $1.7 million to $76.4 million for the nine months ended September 30, 2017. This increase was primarily due to increased activity at the Hardisty terminal, along with the recognition of greater amounts of previously deferred revenues in the current year as compared to the prior year. This was partially offset by five months of decreased revenue due to the discontinuation of operations of our San Antonio facility in May 2017 and approximately one month of decreased revenue at our Casper facility due to the expiration of one of our customer agreements in August 2017. In addition, our terminalling service revenue would have been approximately $0.7 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2017, was the same as the average exchange rate for the nine months ended September 30, 2016.

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 $39.3 million of previously deferred revenues during the nine months ended September 30, 2017, as compared with $36.5 million during the nine months ended September 30, 2016. The recognition of greater amounts of previously deferred revenue in the current period is due to more make-up rights expiring in the current period relative to the same period for the prior year.

Our Stroud terminal commenced operations on October 1, 2017, which will generate additional revenues and operating costs in the fourth quarter of 2017.

Operating Costs

The operating costs of our Terminalling services segment increased $2.1 million to $44.1 million for the nine months ended September 30, 2017. This increase was primarily due to expenses at the Stroud terminal incurred in preparation of the commencement of operations in October 2017. Additionally, increased utilization of our Hardisty terminal resulted in an increase in subcontracted rail services and pipeline fees at our Hardisty terminal. These expenses were partially offset by reduced costs associated with the discontinuation of operations at our San Antonio terminal.

Our terminalling services operating costs for the nine months ended September 30, 2017, would have been approximately $0.2 million less if the average exchange rate for the Canadian dollar in relation to the U.S. dollar for the nine months ended September 30, 2017, was the same as the average exchange rate for the nine months ended September 30, 2016.

Subcontracted rail services. Our subcontracted rail services costs increased $0.1 million to $6.1 million for the nine months ended September 30, 2017, primarily due to increased activity at our Hardisty terminal, along with the addition of services at the Stroud terminal in preparation for the commencement of operations in October 2017. This was partially offset by the discontinuation of operations at our San Antonio terminal.

Pipeline fees. Pipeline fees increased $1.6 million to $17.2 million for the nine months ended September 30, 2017, primarily due to the increase in revenues recognized at the Hardisty terminal as discussed above.

Operating and maintenance. Operating and maintenance expenses decreased approximately $0.4 million to approximately $1.8 million for the nine months ended September 30, 2017, from approximately $2.2 million for the nine months ended September 30, 2016, primarily due to decreased repairs and maintenance activities in 2017 resulting from 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.

Depreciation and amortization. Depreciation and amortization expense increased approximately $0.4 million to approximately $15.2 million for the nine months ended September 30, 2017, primarily due to the additional depreciation expense associated with our Stroud terminal.

Other Expenses

Interest expense. Interest expense for our Terminalling services segment decreased by $0.8 million to $0.2 million for the nine months ended September 30, 2017, from $1.0 million for the nine months ended September 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 the Term Loan 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.

In June 2017, as a part of our purchase of the Stroud terminal and related facilities, we acquired crude oil used by the prior owner for line fill in the crude oil pipeline and tank bottoms for the storage tanks at the Stroud terminal. In September, we also acquired crude oil used for tank bottoms by the prior owner at our leased storage facility in Cushing, Oklahoma. We intend to sell all of this crude oil prior to the end of 2017. We entered into commodity swap contracts to fix the price we will receive upon our sale of the crude oil, as noted above in our analysis for the three months ended September 30, 2017.

From December 31, 2016 to September 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 0.8018 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our currency denominated derivative contracts maturing on or after September 30, 2017, relative to the value of these contracts at December 31, 2016, producing a non-cash loss of approximately $1.2 million for the nine months ended September 30, 2017.

From December 31, 2015 to September 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 0.7609 U.S. dollars for each Canadian dollar. This increase in the exchange rate decreased the value of our currency denominated derivative contracts maturing in 2016 at September 30, 2016, relative to the value of these contracts at December 31, 2015, producing a non-cash loss of approximately $0.9 million for the nine months ended September 30, 2016.

Benefit from income taxes. Our benefit from income taxes for the Terminalling services segment decreased $0.2 million to a benefit of $1.8 million for the nine months ended September 30, 2017, as compared with a benefit of $2.0 million for the nine months ended September 30, 2016. During the nine months ended September 30, 2017, upon filing our Canadian federal and provincial income tax returns for 2016, we further revised our estimates of 2016 Canadian federal and provincial income tax liabilities based on the actual taxable income of our Canadian operations for 2016. As a result, we received refunds totaling approximately $2.6 million (C$3.4 million) during the third quarter of 2017, which reduced our "Provision for income taxes" during the nine months ended September 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. As such, we expect to pay minimal 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 September 30,					Nine Months Ended September 30,
	2017		2016			2017		2016
	(in thousands)
Revenues
Fleet leases	$	1,656	$	1,533		$	4,723	$	4,604
Fleet services	688		754			2,181		2,260
Freight and other reimbursables	118		218			374		932
Total revenues	2,462		2,505			7,278		7,796
Operating costs
Fleet leases	1,656		1,534			4,723		4,605
Freight and other reimbursables	118		218			374		932
Operating and maintenance	95		95			285		241
Selling, general and administrative	210		230			694		631
Total operating costs	2,079		2,077			6,076		6,409
Operating income	383		428			1,202		1,387
Foreign currency transaction loss (gain)	4		(2		)	6		(72		)
Provision for income taxes	196		160			511		142
Net income	$	183	$	270		$	685	$	1,317

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

The underlying business activities associated with our fleet services segment have remained relatively constant for the three months ended September 30, 2017, as compared with three months ended September 30, 2016. As a result, we have experienced only modest changes in the operating revenues and expenses associated with this business. We expect only modest changes in the operating results of our fleet services business until additional railcars and services are required by our customers.

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

As noted above in our analysis for the three months ended September 30, 2017, we have experienced only modest changes in the operating revenues and expenses associated with our fleet services business nine months ended September 30, 2017, as compared with the nine months ended September 30, 2016, and we do not expect any significant changes until additional railcars and services are required by our customers.

Our provision for income taxes associated with our Fleet services segment increased $0.4 million to $0.5 million for the nine months ended September 30, 2017, from $0.1 million for the nine months ended September 30, 2016, due to reversals of temporary differences at USD Rail LP, producing an increase in taxable income. Additionally, we utilized net operating loss carryforwards to reduce taxable income for the nine months ended September 30, 2016, that we do not have available to offset taxable income for the nine months ended September 30, 2017. 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%.

CORPORATE ACTIVITIES

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Operating costs
Selling, general and administrative	$	2,093		$	2,455		$	6,714		$	7,662
Operating loss	(2,093		)	(2,455		)	(6,714		)	(7,662		)
Interest expense	2,388			2,286			7,338			6,320
Foreign currency transaction gain	(441		)	(4		)	(500		)	(4		)
Provision for (benefit from) income taxes	(31		)	—			(177		)	1
Net loss	$	(4,009	)	$	(4,737	)	$	(13,375	)	$	(13,979	)

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

Costs associated with our corporate activities decreased by $0.7 million to $4.0 million for the three months ended September 30, 2017, from $4.7 million for the three months ended September 30, 2016. “Selling, general and administrative” expenses decreased by $0.4 million, primarily due to a decrease in unit based compensation expense related to forfeitures under our Long-term Incentive Plan and of our Class A units. Interest expense increased by $0.1 million during the three months ended September 30, 2017, due to a higher weighted average interest rate, partially offset by a lower weighted average balance of debt outstanding as compared with the same period of 2016.

Nine months ended September 30, 2017 compared with nine months ended September 30, 2016

Costs associated with our corporate activities decreased by $0.6 million to $13.4 million for the nine months ended September 30, 2017, from the nine months ended September 30, 2016. “Selling, general and administrative” expenses decreased by $0.9 million, primarily due to lower consulting costs and legal fees. Our consulting costs were lower due to the completion of a project in the first half of 2016 to enhance our compliance and internal control systems. Our legal fees were lower because we did not incur legal costs for financing and integrating the Casper terminal during the nine months ended September 30, 2017, as we did during the nine months ended September 30, 2016. Interest expense increased by $1.0 million during the nine months ended September 30, 2017, primarily due to higher weighted average rates of interest relative to the same period in 2016. We had a benefit of $0.2 million for income taxes for the nine months ended September 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.

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 partnership interests, either privately or pursuant to our effective shelf

registration statement, as well as cash generated from our operating activities. We believe that cash generated from these sources will be sufficient to meet our ongoing working capital and capital expenditure requirements and to make quarterly cash distributions.

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 senior secured credit agreement, the Credit Agreement, comprised of a $400 million revolving credit facility (subject to the limits set forth therein), or the Revolving Credit Facility, with Citibank, N.A., as administrative agent, and a syndicate of lenders. The Credit Agreement is a five year committed facility that matures on October 15, 2019.

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:



	September 30, 2017		December 31, 2016
	(in millions)
Cash and cash equivalents	$	7.8	$	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	201.0		213.0
Letters of credit outstanding	—		—
Total available liquidity ⁽¹⁾	$	206.8	$	188.6

⁽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.

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

Cash Flows

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



	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Net cash provided by (used in):
Operating activities	$	38,228		$	37,099
Investing activities	(26,708		)	(471		)
Financing activities	(15,246		)	(37,851		)
Effect of exchange rates on cash	(148		)	559
Net change in cash and cash equivalents	$	(3,874	)	$	(664	)

Operating Activities

Net cash provided by operating activities increased by $1.1 million to $38.2 million for the nine months ended September 30, 2017, from $37.1 million for the nine months ended September 30, 2016. The increase was primarily attributable to income tax refunds we received of approximately $2.6 million (C$3.4 million), partially offset by 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 $26.2 million to $26.7 million for the nine months ended September 30, 2017, from $0.5 million for the nine months ended September 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 $15.2 million for the nine months ended September 30, 2017, from $37.9 million for the nine months ended September 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 $22.3 million for the nine months ended September 30, 2017, compared with net repayments of $15.8 million for the nine months ended September 30, 2016. Additionally, we paid cash distributions of $25.5 million and participant withholding taxes associated with vested Phantom Units of $1.1 million during the nine months ended September 30, 2017, both of which exceeded amounts paid during the nine months ended September 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Segment Adjusted EBITDA
Terminalling services	$	14,186		$	17,080		$	46,434		$	50,310
Fleet services	383			428			1,202			1,387
Corporate activities ⁽¹⁾	(1,147		)	(1,328		)	(3,752		)	(4,838		)
Total Adjusted EBITDA	13,422			16,180			43,884			46,859
Add (deduct):
Amortization of deferred financing costs	216			216			646			646
Deferred income taxes	(221		)	98			86			2
Changes in accounts receivable and other assets	3,215			(4,309		)	1,862			(2,802		)
Changes in accounts payable and accrued expenses	2,033			2,027			947			90
Changes in deferred revenue and other liabilities	(3,147		)	(2,599		)	(5,667		)	(499		)
Change in restricted cash	915			(31		)	685			(664		)
Interest expense, net	(2,384		)	(2,572		)	(7,500		)	(7,288		)
Benefit from income taxes	178			5,579			1,427			1,865
Foreign currency transaction gain (loss) ⁽²⁾	457			(25		)	527			120
Deferred revenue associated with minimum monthly commitment fees ⁽³⁾	1,473			(43		)	1,331			(1,230		)
Net cash provided by operating activities	$	16,157		$	14,521		$	38,228		$	37,099


⁽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 Revenue of our consolidated financial statements in Part 1. Item 1.

Terminalling Services Segment

Adjusted EBITDA from our Terminalling services segment decreased $2.9 million to $14.2 million for the three months ended September 30, 2017, from $17.1 million for the three months ended September 30, 2016, and decreased $3.9 million to $46.4 million for the nine months ended September 30, 2017, from $50.3 million for the nine months ended September 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, decreased income from our Casper terminal due to the expiration of one of our customer agreements in August 2017, and a smaller benefit from the settlement of our derivative contracts. 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 has not changed significantly for the three and nine month periods ended September 30, 2017, as compared with the three and nine month periods ended September 30, 2016. The underlying business activities associated with our fleet services segment have remained relatively constant. We have experienced only modest changes in the operating revenues and expenses associated with this business and expect only

modest changes in the operating results of our fleet services business until additional railcars and services are required by our customers.

Cash Requirements

Our primary requirements for cash are to fund capital expenditures, including maintenance capital expenditures, acquisitions and the costs we may incur to construct new assets, in addition to 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 $472 thousand of maintenance capital expenditures during the nine months ended September 30, 2017, primarily for drainage improvements, 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 nine months ended September 30, 2017, was $26.2 million, primarily related to our purchase of the Stroud terminal, which we funded with amounts borrowed on our Revolving Credit Facility and later repaid with a portion of the net proceeds of our equity offering. 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 nine months ended September 30, 2017, we repaid $10.3 million on our Term Loan Facility (the equivalent of C$13.6 million) and $56.0 million on our Revolving Credit Facility. These payments were partially offset by proceeds from borrowing $44.0 million on our Revolving Credit Facility, which we used to fund our purchase of the Stroud terminal, other capital expenditures and for general partnership purposes.

Distributions

We intend to pay a minimum quarterly distribution of at least $0.2875 per unit per quarter. Our current quarterly distribution of $0.345 per unit equates to approximately $9.2 million per quarter, or $36.6 million per year, based on the number of common, Class A, subordinated, and general partner units outstanding as of November 6, 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies and estimates that we use in preparation of our consolidated financial statements are set forth under “Management's Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016. We have not made any material changes to these accounting policies during the three and nine months ended September 30, 2017, other than as discussed below.

Assessment of Recoverability of Goodwill

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

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


(1)	our projections of future financial performance;


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


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


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


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


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

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

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


(1)	Capital expenditures of up to $12 million for additional terminalling connectivity and unloading racks;


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


(3)	A weighted average cost of capital of 10.5%;


(4)	A capital structure consisting of approximately 35% debt and 65% equity;


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


(6)	A range of EBITDA multiples for transactions based on actual sales and purchases of comparable businesses, from 8.25x to 9.25x.

The key assumptions listed above were based upon economic and other operational conditions existing at or prior to the July 1, 2017, valuation date. Our weighted average cost of capital is subject to variability and is dependent upon such factors as changes in benchmark rates of interest established by the Federal Open Market Committee of the Federal Reserve Board, the British Bankers Association and other central banking regulatory authorities, as well as perceptions of risk and market uncertainty regarding our business, industry and those of our peers and our underlying capital structure. We expect our long-term underlying capital structure to approximate a weighting of 50% debt and 50% equity. Each of the above assumptions are likely to change due to economic uncertainty surrounding global and North American energy markets that are highly correlated with crude oil, natural gas and other energy-related commodity prices and other market factors.

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

The EBITDA multiples we used to estimate the fair value of the Casper terminal reporting unit are subject to uncertainty associated with market conditions in the energy sector. We derived our assumptions based upon the EBITDA multiples from recent transactions involving several comparable businesses that operate in the midstream energy sector, generally providing services associated with the transportation of energy-related products. The EBITDA multiples of

each of these entities is affected by changes in the supply of and demand for energy-related products, which affects the demand for the services they provide. Declines in the production of energy-related products as well as lower demand for these products can reduce the operating results of these organizations and, accordingly, the multiples that market participants are willing to pay. Changes in the EBITDA multiples of these comparable businesses we use to estimate fair value could significantly affect the fair value of the Casper terminal reporting unit we derived using this approach.

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

As indicated above, our estimate of fair value for the Casper terminal reporting unit required us to use significant unobservable inputs representative of Level 3 fair value measurements, including assumptions related to the future performance of our Casper terminal. During the third quarter of 2017, we completed our annual goodwill impairment analysis and determined that the fair value of the Casper terminal reporting unit exceeded its carrying value at July 1, 2017. An impairment charge would have resulted if our estimate of the fair value of the Casper terminal reporting unit was approximately 5% less than the amount determined. We have not observed any events or circumstances subsequent to our analysis that would suggest the fair value of our Casper terminal is below its carrying amount as of September 30, 2017.

Impairment of Long-lived Assets

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable.

We consider a long-lived asset to be impaired when the sum of the estimated, undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset, or a significant change in the asset’s physical condition or use.

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

In late August 2017, a customer contract for terminalling services at our Casper terminal expired and was not renewed. The expiration of this contract represented a trigger event that required us to assess the recoverability of our long-lived assets associated with the Casper terminal at August 31, 2017. Our assessment of recoverability includes projected cash flow assumptions expected to be derived from our operation of the Casper terminal without regard to any expansion of its existing service potential at August 31, 2017. The assumptions underlying our cash flow projections include our ability to renew existing contracts and expand business with current customers, and our ability to enter into contracts with new customers and obtain additional commitments regarding the use of these facilities. The critical assumptions underlying our projections include:


•	Widening price differentials, or spreads, between the WCS and WTI crude oil pricing indices;


•	Increasing demand from West Coast refineries for Canadian crude oil due to the widening price differentials between WCS and alternative crude oil feedstocks that are priced off of the WTI or Brent pricing indices;


•	Incremental volumes of approximately 7,700 Bpd for terminalling and storage services resulting from increasing demand from West Coast refineries for Canadian crude oil;


•	Expansion of blending services business for distribution to local refineries;


•	Operating expense reductions due to cost savings initiatives;


•	An eight year remaining useful life of the primary asset, represented by our customer service agreement intangible asset of the Casper terminal asset group; and


•	A residual value of 9x projected cash flows for the Casper terminal at the end of the eight year remaining life of the primary asset.

To the extent that our assumptions as set forth above do not materialize as assumed, our projections of future financial performance underlying our cash flow projections for the Casper terminal could yield undiscounted cash flows and a fair value that indicate our long-lived assets are impaired.


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 September 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	—	—			290
December 29, 2017	C$	8,400,000	0.7809	0.8028	(184		)	282
Total					$	(184	)	$	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 September 30, 2017.

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

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

variability in crude oil prices during the month of October 2017. The swap contract effectively fixes the price we will receive upon our delivery of the crude oil and will settle in October 2017 at $47.90 per barrel.

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



	At September 30, 2017
	Notional	Market Price ⁽¹⁾		Fixed Price ⁽²⁾		Fair Value
	(in Bbl)					(in thousands)
Commodity swaps maturing in 2017
July 2017 ⁽³⁾	18,395	$	—	$	47.20	$	—
October 2017	13,383	$	51.76	$	47.70	$	(54	)
October 2017	30,000	$	51.76	$	47.90	(116		)
	61,778					$	(170	)


⁽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 September 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.


⁽³⁾	The market price for the commodity swap on July 14, 2017, the date we sold the crude oil, was $47.64.


Item 4.	Controls and Procedures.

DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 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 September 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 September 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 currently a party to any litigation that will have a material adverse impact on our financial condition, results of operations or statements of cash flows. We are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the 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 nine months ended September 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:	November 8, 2017	By:	/s/ Dan Borgen
			Dan Borgen Chief Executive Officer and President (Principal Executive Officer)

Date:	November 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. (incorporated by reference herein to Exhibit 10.1 of the Quarterly Report on Form 10-Q (File No. 001-36674) filed on August 8, 2017).

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.

USD Partners - 10-Q quarterly report FY

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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	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 4.	Controls and Procedures	59

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 6.	Exhibits	60
SIGNATURES		61